Downhole devices for providing sealing components within a wellbore, wells that include such downhole devices, and methods of utilizing the same

ABSTRACT

Downhole devices, wells that include the downhole devices, and methods of utilizing the same are disclosed herein. The downhole devices include a core; a sealing component holder positioned within the core including an opening to an external surface of the core; a plurality of sealing components positioned within the sealing component holder; a metering device; and a cover positioned over the opening. The metering device is constructed and arranged to displace an internal volume of the sealing component holder and discharge through the opening a portion of the plurality of sealing components contained within the sealing component holder. The cover is constructed and arranged to allow the portion of the sealing components to exit the opening upon displacement of the internal volume of the sealing component holder.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser.No. 62/423,801, filed Nov. 18, 2016 entitled “Downhole Devices forProviding Sealing Components Within A Wellbore, Wells That Include SuchDownhole Devices, and Methods of Utilizing the Same,” U.S. ProvisionalApplication Ser. No. 62/263,069, filed Dec. 4, 2015 entitled“Select-Fire, Downhole Shockwave Generation Devices, Hydrocarbon WellsThat Include The Shockwave Generation Devices, and Methods of Utiizingthe Same;” and U.S. application Ser. No. 15/264,076 filed Sep. 13, 2016entitled, “Select-Fire, Downhole Shockwave Generation Devices,Hydrocarbon Wells That Include The Shockwave Generation Devices, andMethods of Utiizing the Same,” the entireties of which are incorporatedby reference herein.

This application is related to U.S. Provisional Application Ser. No.62/262,034 filed Dec. 2, 2015, entitled, “Selective Stimulation Ports,Wellbore Tubulars That Include Selective Stimulation Ports, and Methodsof Operating the Same,” (Attorney Docket No. 2015EM360); U.S.Provisional Application Ser. No. 62/262,036 filed Dec. 2, 2015,entitled, “Wellbore Tubulars Including A Plurality of Selective Portsand Methods of Utilizing the Same,” (Attorney Docket No. 2015EM361);U.S. Provisional Application Ser. No. 62/263,065 filed Dec. 4, 2015,entitled, “Wellbore Ball Sealer and Methods of Utilizing the Same,”(Attorney Docket No. 2015EM369); U.S. Provisional Application Ser. No.62/411,890 filed Oct. 24, 2016, entitled, “Sealing Devices, WellboreTubulars Including The Sealing Devices, And Hydrocarbon Wells IncludingThe Wellbore Tubulars,” (Attorney Docket No. 2015EM369); U.S.Provisional Application Ser. No. 62/263,067 filed Dec. 4, 2015,entitled, “Ball-Sealer Check-Valves for Wellbore Tubulars and Methods ofUtilizing the Same,” (Attorney Docket No. 2015EM370); and U.S.Provisional Application Ser. No. 62/411,004 filed Oct. 21, 2016,entitled, “Selective Stimulation Ports Including Sealing DeviceRetainers and Methods of Utilizing the Same,” (Attorney Docket No.2015EM370), the disclosures of which are incorporated herein byreference in their entireties.

FIELD OF THE DISCLOSURE

The present disclosure is directed to downhole devices for providingsealing components proximal a section of the well to be sealed, to wellsthat include such downhole devices, and to methods of utilizing suchdownhole devices and/or wells.

BACKGROUND OF THE DISCLOSURE

Hydrocarbon wells generally include a wellbore that extends from asurface region through a subterranean formation to a reservoir withinthe subterranean formation containing reservoir fluid, such as liquidand/or gaseous hydrocarbons. Often, it may be desirable to stimulate thesubterranean formation to enhance production of the reservoir fluidtherefrom. Stimulation of the subterranean formation may be accomplishedin a variety of ways and generally includes supplying a stimulant fluidto the subterranean formation to increase reservoir contact. As anexample, the stimulation may include supplying an acid as the stimulantfluid to the subterranean formation to acid-treat the subterraneanformation to dissolve at least a portion of the subterranean formationand/or remove cement materials placed between the casing tubular conduitand the subterranean formation. As another example, the stimulation mayinclude fracturing the subterranean formation, such as by supplying afracturing fluid as the stimulant fluid, which is pumped at a highpressure, into the subterranean formation. The fracturing fluid mayinclude particulate material, such as a proppant, which may at leastpartially fill fractures that are generated during the fracturing,thereby facilitating fluid flow within the fractures after supply of thefracturing fluid has ceased.

A variety of systems and methods have been developed to facilitatestimulation of subterranean formations. Such systems and methods utilizea shape-charge perforation gun to create perforations within a sectionof the tubular casing string extending within the wellbore, and thestimulant fluid then is provided to the subterranean formation via theperforations. Once stimulation is complete in the particular region ofthe subterranean formation proximal to the perforated section of thetubular casing string, ball sealers are introduced into the perforatedsection of the tubular casing string to seal the perforations and anadditional section of the tubular casing string is perforated proximalan additional region of the subterranean formation to stimulate theadditional region of the subterranean formation. This process isrepeated until stimulation of the subterranean formation is complete.

With respect to sealing the perforations after stimulation within aregion is complete, ball sealers may be introduced from the surfaceregion via a ball injector, transported down into the tubular casingstring via a high velocity carrier fluid having a suitable density, andallowed to engage with the perforations within the section. However, theflow profile in the tubular casing string, changing pump rates, and thefluid properties of the high velocity carrier fluid tend to distributethe ball sealers along the axial length of the tubular casing stringand, thus, delivers the ball sealers at the desired location within thetubular casing string at different times. Ball sealers can sometimes bedistributed within as much as ten percent (10%) of the calculatedarrival volume of the wellbore fluid and, thus, arrive at the desiredlocation either too early or too late.

Alternatively, the ball sealers may be introduced locally to the sectionof the tubular casing string to be sealed. U.S. Patent ApplicationPublication No. 2016/0168962 to Tolman et al. is directed to multizonefracture stimulation of a reservoir which utilizes a plurality ofperforation gun assemblies made of a friable material. A firstperforation gun assembly is deployed into the wellbore to perforate afirst selected zone of interest. A second perforating gun assembly issubsequently deployed into the wellbore to perforate a second selectedzone of interest; however, the second perforating gun assemblyadditionally includes a ball container including a sufficient amount ofball sealers to seal the perforations of the first selected zone ofinterest. The ball sealers may be released from the ball container priorto or simultaneously with the firing of the second perforating gunassembly. A single container containing an amount of ball sealers toseal only the first selected zone of interest is used because thefriable perforating gun assemblies are destroyed upon firing theexplosive shape-charges contained therein.

U.S. Pat. No. 8,561,696 to Trummer et al. is also directed to multizonefracture stimulation of a reservoir which either utilizes tags withinthe ball sealers or high velocity carrier fluid to determine thelocation of the ball sealers as they are transported from the surface tothe desired section of the well or containers positioned locally withinthe well at axially spaced apart locations to release the ball sealerscontained therein to seal perforations within a desired section of thewell. The containers may be coupled to the tubular casing string or maybe provided with the perforating gun assembly below an associatedperforating gun section on the assembly. Each container is configuredfor a single release of ball sealers, therefore, only an amount of ballsealers required to seal perforations within a particular perforatedzone are included within a container. When the containers are includedwithin the perforating gun assembly, a container located below the firedperforating gun section and/or the connections thereto will be destroyedupon firing. Further, when containers are coupled to the tubular casingstring, the placement of such containers must be determined prior tocoupling to the tubular casing string limiting the flexibility indeployment of the ball sealers.

Such methods of introducing ball sealers to seal perforations ofmultiple, axially spaced-apart sections of the tubular casing stringintroduce ball sealers from the surface or use multiple local sources ofball sealers to separately seal each particular perforated zone and donot provide an individual local source capable of delivering ballsealers to perforations within multiple, axially spaced-apart sectionsof the tubular casing string at different time periods.

Thus, there exists a desire to provide a downhole device to deliverspecific and varying amounts of sealing components, as needed duringoperations, into multiple, axially spaced-apart sections of a well froma single local source capable of being positioned at variable depthswithin a wellbore providing variable depth control.

SUMMARY OF THE DISCLOSURE

Downhole devices, wells that include the downhole devices, and methodsof utilizing the same are disclosed herein. The downhole devices areconfigured to provide sealing components within a well to a plurality ofaxially spaced-apart sections of the well. The downhole devices includea core, a sealing component holder, a plurality of sealing components, ametering device, and a cover. The sealing component holder is positionedwithin the core and includes an opening to an external surface of thecore. The plurality of sealing components are positioned within thesealing component holder. The metering device is constructed andarranged to displace an internal volume of the sealing component holderand discharge through the opening a portion of the plurality of sealingcomponents contained within the sealing component holder. The cover ispositioned over the opening and constructed and arranged to allow theportion of the sealing components to exit the opening upon displacementof the internal volume of the sealing component holder.

As an example, the downhole device may be a shockwave generation deviceadditionally configured to generate a shockwave within a wellbore fluidthat extends within a tubular conduit of a wellbore tubular. Theshockwave generation devices may additionally include a plurality ofexplosive charges arranged on an external surface of the core and aplurality of triggering devices. Each of the plurality of triggeringdevices is associated with a selected portion of the plurality ofexplosive charges and is configured to selectively initiate explosion ofthe selected portion of the plurality of explosive charges.

Also described in the present disclosure are methods for providingsealing components within a well. The well includes a wellbore and awellbore tubular extending within the wellbore, the wellbore tubulardefining a tubular conduit. The method includes positioning a downholedevice proximal to or within a first region within the tubular conduitradially interior of a first section of the wellbore tubular. Thedownhole device includes a core, a sealing component holder, a pluralityof sealing components, a metering device, and a cover. The sealingcomponent holder is positioned within the core and includes an openingto an external surface of the core. The plurality of sealing componentsare positioned within the sealing component holder. The metering deviceis constructed and arranged to displace an internal volume of thesealing component holder and discharge through the opening a portion ofthe plurality of sealing components contained within the sealingcomponent holder. The cover is positioned over the opening andconstructed and arranged to allow the portion of the sealing componentsto exit the opening upon displacement of the internal volume of thesealing component holder. The method also includes actuating themetering device to displace a first internal volume of the sealingcomponent holder to discharge a first portion of the plurality ofsealing components through the opening into the tubular conduit;positioning the downhole device proximal to or within a second regionwithin the tubular conduit radially interior of a second section of thewellbore tubular, the second region spaced apart from the first regionalong the length of the wellbore tubular; and actuating the meteringdevice to displace a second internal volume of the sealing componentholder to discharge a second portion of the plurality of sealingcomponents through the opening into the tubular conduit.

As an example, the methods may additionally include positioning thedownhole device, such as a shockwave generation device, within the firstregion of the tubular conduit and actuating a first triggering device.The first triggering device initiates explosion of a first explosivecharge and generates a first shockwave within the first region of thetubular conduit. The first shockwave causes one or more selectivestimulation ports (SSPs) present in the wellbore tubular to transitionfrom a closed state to an open state. The methods may further includepositioning the shockwave generation device within the second region ofthe tubular conduit and actuating a second triggering devicesimultaneously with or subsequently to the first region of the tubularconduit being sealed. The second triggering device initiates explosionof a second explosive charge and generates a second shockwave within thesecond region of the tubular conduit. The second shockwave causes one ormore SSPs present in the wellbore tubular to transition from a closedstate to an open state. Once an SSP is opened by a shockwave from theshockwave generation device, the SSPs may permit fluid flow between thewellbore tubular and the subterranean formation until subsequentlysealed with sealing components.

Also described herein are wells including such downhole devices; methodsfor fracturing a subterranean formation which includes the methods forproviding sealing components within a hydrocarbon well; and methods fordiverting injection fluid within an injection well which includes themethods for providing sealing components within the injection well.

BRIEF DESCRIPTION OF THE DRAWINGS

While the present disclosure is susceptible to various modifications andalternative forms, specific exemplary implementations thereof have beenshown in the drawings and are herein described in detail. It should beunderstood, however, that the description herein of specific exemplaryimplementations is not intended to limit the disclosure to theparticular forms disclosed herein. This disclosure is to cover allmodifications and equivalents as defined by the appended claims. Itshould also be understood that the drawings are not necessarily toscale, emphasis instead being placed upon clearly illustratingprinciples of exemplary embodiments of the present disclosure. Moreover,certain dimensions may be exaggerated to help visually convey suchprinciples. Further where considered appropriate, reference numerals maybe repeated among the drawings to indicate corresponding or analogouselements. Moreover, two or more blocks or elements depicted as distinctor separate in the drawings may be combined into a single functionalblock or element and blocks or elements may be arranged in any suitablemanner. Similarly, a single block or element illustrated in the drawingsmay be implemented as multiple steps or by multiple elements incooperation and may be implemented in any suitable order or sequence.

FIG. 1 is a schematic representation of a side (axial cross-sectional)view of a hydrocarbon well that may include and/or utilize a downholedevice according to the present disclosure.

FIG. 2 is a schematic representation of a side (axial cross-sectional)view of a downhole device according to the present disclosure.

FIG. 3 is a more detailed but still schematic representation of a frontview of a cover for the downhole device of FIG. 2.

FIG. 4 is a more detailed but still schematic representation of a frontview of a cover for the downhole device according to the presentdisclosure.

FIG. 5 is a more detailed but still schematic representation of a frontview of a cover for the downhole device of FIG. 2.

FIG. 6 is a more detailed but still schematic representation of a frontview of a cover for the downhole device of FIG. 2.

FIG. 7 is schematic representation of a partial side (axialcross-sectional) view of a downhole device.

FIG. 8 is a schematic representation of a partial side (axialcross-sectional) view of a downhole device according to the presentdisclosure.

FIG. 9 is a schematic representation of a partial side (axialcross-sectional) view of a downhole device according to the presentdisclosure.

FIG. 10 is a schematic representation of a partial side (axialcross-sectional) view of a downhole device according to the presentdisclosure.

FIG. 11 is a schematic representation of a partial side (axialcross-sectional) view of a downhole device according to the presentdisclosure.

FIG. 12 is a schematic representation of a side (axial cross-sectional)view of a hydrocarbon well that may include and/or utilize a shockwavegeneration device according to the present disclosure.

FIG. 13 is a schematic representation of a side (axial cross-sectional)view of a shockwave generation device according to the presentdisclosure.

FIG. 14 is a more detailed but still schematic representation of a side(axial cross-sectional) view of a selective stimulation port accordingto the present disclosure.

FIG. 15 is a more detailed but still schematic representation of a sideview of a portion of the shockwave generation device of FIG. 13.

FIG. 16 is a less detailed schematic side view of a shockwave generationdevice according to the present disclosure.

FIG. 17 is a transverse (radial cross-sectional) view of a shockwavegeneration device showing examples of flutes and protective barriersthat may be included in shockwave generation device according to thepresent disclosure.

FIG. 18 is a less detailed schematic side view of a shockwave generationdevice according to the present disclosure.

FIG. 19 is a transverse (radial cross-sectional) view of the shockwavegeneration device of FIG. 18 taken along line 7-7 of FIG. 18.

FIG. 20 illustrates examples of various transverse (radialcross-sectional) views of shapes for flutes that may be defined by acore of a shockwave generation device according to the presentdisclosure.

FIG. 21 is a flowchart depicting a method, according to the presentdisclosure, of metering sealing components within a tubular conduit.

FIG. 22 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 23 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 24 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 25 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 26 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 27 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 28 is a schematic side (axial cross-sectional) view of a portion ofa process flow for generating a plurality of shockwaves within asubterranean formation.

FIG. 29 is a flowchart depicting a method, according to the presentdisclosure, of metering sealing components within a tubular conduit.

FIG. 30 is a schematic side (axial cross-sectional) view of a portion ofa process flow for metering sealing components within a tubular conduitduring refracturing operations.

FIG. 31 is a flowchart depicting a method, according to the presentdisclosure, of metering sealing components within a tubular conduit ofan injection well.

FIG. 32 is a schematic side (axial cross-sectional) view of a portion ofa process flow for metering sealing components within a tubular conduitduring injection operations.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

The present disclosure is directed to a downhole device constructed andarranged to provide multiple, metered amounts of sealing components(sealing devices) from an individual sealing component holder containedwithin the downhole device. The metered amounts of sealing componentsare discharged from the downhole device proximal the section of thewellbore tubular or subterranean formation to be sealed. Such a downholedevice releases the sealing components locally over a short period oftime which provides the sealing components to the targeted section ofthe wellbore tubular in a concentrated manner. As discussed above,releasing sealing components into the wellbore tubular from the surfaceresults in the axial distribution or dispersion of the sealingcomponents within the carrier fluid used to transport the sealingcomponents to the targeted section of the wellbore tubular. Distributionor dispersion of the sealing components occurs due to the flow profilewithin the wellbore tubular and the fluid properties of the carrierfluid. Further, in order to minimize or prevent contact of the sealingcomponents with stimulant fluid or fracturing fluid traveling ahead ofthe carrier fluid while the sealing components are transported to thetarget section of the wellbore tubular, a significant amount of carrierfluid is introduced into the wellbore prior to the release of thesealing components from the surface. The introduction of the excesscarrier fluid can lead to over displacement of proppant in the fracturewhich can in turn negatively affect well performance.

As discussed above, including a container within a perforation gun canlimit the ability to use an individual source of ball sealers to providemultiple, metered amounts of ball sealers to perforations withinmultiple, axially spaced-apart sections of the tubular casing string atdifferent time periods. This results from the fact that the area nearthe detonated portion of the perforation gun and below, including anycontainer and connections thereto, is significantly damaged upon firingof the shape-charges. The downhole device of the present disclosureovercomes such limitations and provides the ability to locally releasemultiple, metered amounts of sealing components from an individualsealing component holder within the downhole device which can providethe sealing component to the target section of the wellbore tubular in aconcentrated manner without significant axial displacement ordispersion, eliminate introducing excess stimulant fluid or fracturingfluid into the fracture, allow the use of sealing components that areoversized or undersized, provide multiple, precise placements of thesealing components contained within a sealing component holder of adownhole device in a single trip downhole, precise placement of multipleportions of a plurality of sealing components contained within a sealingcomponent holder wherein the portions of sealing components can havedifferent properties or different amounts, and/or provide sealingcomponents that may be oversized or undersized.

Elements that serve a similar, or at least substantially similar,purpose may be labeled with like numbers in each of FIGS. 1-32, andthese elements may not be discussed in detail herein with reference toeach of FIGS. 1-32. Similarly, all elements may not be labeled in eachof FIGS. 1-32, but reference numerals associated therewith may beutilized herein for consistency. Elements, components, and/or featuresthat are discussed herein with reference to one or more of FIGS. 1-32may be included in and/or utilized with any of FIGS. 1-32 withoutdeparting from the scope of the present disclosure. In general, elementsthat are likely to be included in a particular embodiment areillustrated in solid lines, while elements that are optional may beillustrated in dashed lines. However, elements that are shown in solidlines may not be essential and, in some embodiments, may be omittedwithout departing from the scope of the present disclosure.

FIG. 1 is a schematic representation of a hydrocarbon well 10 that mayinclude and/or utilize a downhole device 190 according to the presentdisclosure. Hydrocarbon well 10 may include a wellbore 20 that extendsfrom a surface region 30 to subterranean formation 34 through subsurfaceregion 32. Subterranean formation 34 includes a reservoir fluid 36, suchas a liquid hydrocarbon and/or a gaseous hydrocarbon, and hydrocarbonwell 10 may be utilized to produce, pump, and/or convey the reservoirfluid 36 from the subterranean formation 34 to the surface region 30.Wellbore 20 may include a vertical section 20A, as illustrated inFIG. 1. Wellbore 20 may also include a horizontal section 20B. Wellbore20 may also include a deviated section 20C located between verticalsection 20A and horizontal section 20B. Hydrocarbon well 10 may furtherinclude wellbore tubular 40, which extends within wellbore 20 anddefines a tubular conduit 42. Wellbore fluid 22 extends within thetubular conduit 42.

As shown in FIG. 1, downhole device 190 may be an umbilical-attacheddownhole device 190 that may be operatively attached to and may bepositioned within tubular conduit 42 via, an umbilical 192, such as awireline, a tether, tubing, jointed tubing, and/or coiled tubing. Theumbilical 192 may permit and/or facilitate positioning of the downholedevice 190 within the tubular conduit 42 and/or may permit and/orfacilitate communication with and/or power to the downhole device 190from surface region 30. Umbilical 192 may convey one or more statussignals from downhole device 190 to a control system (not shown) locatedat surface region 30 and/or may convey one or more control signals fromthe control system located at surface region 30 to downhole device 190.Such an umbilical-attached downhole device 190 may include an anchor 193that may be configured to receive and/or to be operatively attached tothe umbilical 192, as illustrated in FIG. 2.

As another example, the downhole device 190 may be an autonomousdownhole device that may be flowed into and/or within tubular conduit 42without an attached umbilical. When downhole device 190 is an autonomousdownhole device, hydrocarbon well 10 may further include a wirelessdownhole communication network 39, which may be configured to wirelesslycommunicate with the downhole device 190, such as to convey one or morestatus signals from the downhole device 190 to a control system locatedat surface region 30 and/or to convey one or more control signals fromthe control system located at surface region 30 to the downhole device190. One or more batteries may be included within the autonomousdownhole device to provide electrical power to the components of thedownhole device 190.

FIG. 2 is a schematic representation of a downhole device 190 accordingto the present disclosure. Downhole device 190 includes a core 102, asealing component holder 180, sealing components 182, and a meteringdevice 186. The sealing components 182 are positioned within the sealingcomponent holder 180. Member 184 may also be positioned within theinterior of the sealing component holder 180. Sealing component holder180 includes an opening 189 which is configured, shaped and sized suchthat the sealing components contained therein may be released from theinterior of the sealing component holder 180 upon displacement of aninternal volume of the sealing component holder 180. A cover 187 ispositioned over opening 189.

The core of the downhole device may include any suitable structureand/or material that may have, form, and/or define at least a portion ofthe external surface of the downhole device. As examples, the core mayinclude and/or be an elongate core, a rigid core, a metallic core, apartially solid core, a hollow core, and/or an elongate rigid core. Theexternal surfaces of the core may be substantially solid except for anopening to a sealing component holder and openings to accommodateconnections to the downhole device such as an umbilical connection. Itis within the scope of the present disclosure that the core may or maynot be an enclosed tubular. The core may be a single-piece and/ormonolithic structure. Alternatively, the core may be a multi-piece corethat includes a plurality of core segments. Each core segment may beoperatively attached to one or more adjacent core segments to formand/or define the core. As an example, the core segments may behermetically sealed to one another to form and/or define the core.

The downhole device includes a sealing component holder. The downholedevice may include more than one sealing component holder, such as aplurality of sealing component holders. Each sealing component holderincludes an opening to an external surface of the core. As an example,the opening may be in a bottom surface of the downhole device such thatthe sealing components do not pass between a side surface of thedownhole device and an inner surface of the wellbore tubular. A cover ispositioned over each sealing component holder opening and is constructedand arranged to allow a portion of the sealing components to exit theopening upon displacement of an internal volume of the sealing componentholder. The cover may be any suitable structure and/or material thatallows the sealing components to exit the holder upon displacement of aninternal volume and otherwise retains the sealing components within thesealing component holder. As an example, FIG. 3 illustrates cover 187may be a spring loaded cover including a spring 187A disposed about arod 187 B which is disposed through openings 187C in the cover 187providing suitable tension to hold the cover tight against an externalsurface of the core proximal the opening (not shown) except when aninternal volume is being displaced. As another example, FIG. 4illustrates cover 187 may be a rotating cover which overlaps the opening(not shown) of the core and is constructed and arranged to rotate thecover to align an opening 187D with the opening 189 (not shown) of thecore to release sealing components. The rotating mechanism (not shown)may be operatively connected to the cover 187 in any suitable manner. Asanother example, FIGS. 5 and 6 illustrate cover 187 may be a flexiblecover made of a flexible material overlapping the opening (not shown) inthe surface of the core and including an opening 1871 or slit 187Hproximate the center of the flexible cover. The slit may be constructedand arranged to allow the sealing components to pass through the slitupon actuation of the metering device. The cover opening 1871 of FIG. 6may be constructed and arranged to retain the sealing components untilthe metering device is actuated to push the sealing components throughthe cover opening 1871.

A sealing component holder may have any suitable shaped interior whichis able to contain the sealing components and release the sealingcomponents upon displacement of an internal volume of the sealingcomponent holder. The sealing component holder may form a portion of theinternal volume of the core. As an example, the sealing component holdermay form a majority of the internal volume of the core. As an example,the radial cross-section of the sealing component holder may be circularor elliptical. As an example, the radial cross-sectional dimension ordiameter of the interior of the sealing component holder may beconstructed and arranged to be of similar dimension or diameter of thesealing component or may be constructed and arranged to house sealingcomponents two, three, or more radially across. As an example, theinternal volume of the sealing component holder may include a pluralityof members that extend radially inward of an inner surface of thesealing component holder to form slots to hold the sealing componentswithin the sealing component holder.

The internal volume of the sealing component holder may include aplurality of axially spaced apart regions. Each region including aportion of the plurality of sealing components. As illustrated in FIG.7, a sealing component holder 180 may include a first region 180Acontaining a first portion of the plurality of sealing components 182A,a second region 180B containing a second portion of the plurality ofsealing components 182B, a third region 180C containing a third portionof the plurality of sealing components 182C, etc. As an example, thedifferent portions of the plurality of sealing components may havedifferent properties from the sealing components in adjacent regionswithin the sealing component holder. As another example, each regionwithin a sealing component holder may contain a portion of the pluralityof sealing components with different properties from each of the otherportions of the plurality of sealing components. The properties mayinclude composition, size, specific gravity, rate of degradation,non-degradability, and any combinations thereof. Size of the sealingcomponents includes the maximum outer dimension and/or diameter of thesealing component.

As an example, each region within a sealing component holder contains aplurality of sealing components, such as ball sealers, the rate ofdegradation being different from the plurality of sealing components ofeach of the other regions within the sealing component holder. The rateof degradation being the greatest for the first region within thesealing component holder proximal the opening and being the least forthe last region within the sealing component holder distal the opening.Additionally or alternatively, the size and/or specific gravity beingdifferent from the plurality of sealing components of each of the otherregions within the sealing component holder.

The downhole device may include a plurality of sealing componentholders. The sealing components within each sealing component holder maybe the same or may be different. As an example, the downhole device mayinclude a first sealing component holder containing a plurality of ballsealers as the sealing components and a second sealing component holdercontaining a plurality of chemical diverters as the sealing components.This arrangement allows the same downhole device to be used to seal thewellbore tubular with ball sealers and to seal the subterraneanformation exterior of openings in a wellbore tubular with chemicaldiverters which may be performed in a single trip from the surfacedownhole.

As another example, the downhole device may include a first sealingcomponent holder including a plurality of degradable ball sealers as thesealing components and a second sealing component holder including aplurality of non-degradable ball sealers as the sealing components. Thefirst sealing component holder may include a plurality of regions, eachregion within the first sealing component holder may contain a pluralityof sealing components, such as ball sealers, having a substantiallydifferent rate of degradation, as discussed in more detail herein. Thisarrangement allows the same downhole device to be used to temporarilyseal sections of the wellbore tubular with degradable ball sealers andto subsequently seal sections of the wellbore tubular withnon-degradable ball sealers.

The plurality of sealing components may be any suitable structure and/ormaterial to seal a wellbore tubular or subterranean formation exteriorof the wellbore tubular. The plurality of sealing components may beselected from ball sealers, chemical diverters, other physicalcomponents sized and dimensioned to physically seal a wellbore tubularor subterranean formation, and any combinations thereof. An example of asuitable sealing component may be a PERF PODS″ sealing component that isavailable from Thru Tubing Solutions, Inc. of Oklahoma City, Okla. APERF PODS' sealing component includes a primary sealing core from whicha plurality of secondary tendrils extends to form secondary seals, suchas of one or more leakage pathways between the primary sealing core andthe sealing device seat.

The term “ball sealers” as used herein is meant to include any solid,semi-rigid, deformable object having suitable dimensions to individuallyseal an opening, such as a perforation or a SSP, within the wall of thewellbore tubular. Ball sealers may be made of a single material or acomposite material, either material suitable for deforming into a shapesufficient of sealing, but not extruding through, the opening onto whichit is seated. The composite material for the ball sealers may includetwo or more regions or layers of different composition. As an example,ball sealers may be formed having a hard inner core region and a softouter region sufficiently compliant to sealingly engage an openingwithin the wellbore tubular. The material for the inner core may beselected from nylon, phenolic resin, neoprene rubber, syntactic foam,and metallic materials such as aluminum. The material for the outerregion may be selected from elastomers and soft rubbers, such asethylene propylene diene monomer (EPDM), nitrile butadiene rubber (NBR),hydrogenated nitrile butadiene rubber (HNBR), and the like.

Ball sealers may be made of degradable or non-degradable materials.“Degradable” as used herein is meant to include materials that decomposeover a period of time and/or at least partially dissolve upon contactwith a fluid. Degradation may be characterized by time, temperature,and/or fluid type (e.g., oil, water, acidity). The fluid may be awater-based fluid or an oil-based fluid. The water-based fluid may be anacidic fluid. “Non-degradable” as used herein is meant to includematerials that are stable and do not decompose over a reasonable periodof time for intended operations.

Ball sealers may be made of degradable materials which degrade in thepresence of water and may be selected from polyglycolic acid polymermaterials, such as polyglycolic acid semicrystalline polyester,polylactic acid polymer materials, and the like. Ball sealers may bemade of degradable materials which degrade in the presence of oil, suchas alpha-olefins. Ball sealers may be made of degradable materials whichdegrade in the presence of acid such as nylon.

All or a portion of a ball sealer may be made of a degradable material.As an example, a ball sealer may have an inner core formed of anon-degradable material and one or more outer regions of degradablematerial.

Other materials which may be used to form ball sealers may be selectedfrom poly-L-lactic acid, polyetheretherketone, epoxy resin, polystyrene,poly-methylmethacrylate, high density polyethylene, polypropylene,polyamide, polycarbonate, poly-phenylene sulfide, and any combinationsthereof.

Ball sealers may be buoyant, neutrally buoyant, and/or non-buoyant withrespect to the wellbore fluid in which the ball sealers are disposed.Ball sealers may be of any suitable size and shape to sealingly engagewith an opening within the wall of the wellbore tubular. Ball sealersmay be spherical or polygonal. Ball sealers may have a maximum outerdimension and/or diameter in the range of from 5 millimeters (mm) to 76mm or from 10 mm to 50 mm. Ball sealer may have a maximum outerdimension and/or diameter in the range of from 15 mm to 30 mm or from 22mm to 25.5 mm. Ball sealers may be oversized or undersized. “Undersized”is meant to include ball sealers having a maximum outer dimension and/ordiameter that is less than what could typically be delivered downholefrom the surface. Undersized ball sealers may have a maximum outerdimension and/or diameter of less than 15 mm or less than 12 mm.Undersized ball sealers may have a maximum outer dimension and/ordiameter in the range of from 5 mm to less than 15 mm or from 5 mm toless than 12 mm. “Oversized” is meant to include ball sealers having amaximum outer dimension and/or diameter that is greater than what couldtypically be delivered downhole having to pass between the inner surfaceof the wellbore tubular and the outer surface of the downhole device.Oversized ball sealers may have a maximum outer dimension and/ordiameter of greater than 25.5 mm, or greater than 32 mm or greater than50 mm. Oversized ball sealers may have a maximum outer dimension and/ordiameter in the range of from greater than 25.5 mm to 76 mm or fromgreater than 32 mm to 76 mm or from greater than 50 mm to 76 mm.

The plurality of sealing components may include chemical diverters.Chemical diverters may be solid particles of chemical components,viscoelastic surfactants, polymer gels, foams, and any combinationsthereof used to seal porous and permeable portions of the subterraneanformation and/or fractures formed within the subterranean formation. Thechemical diverters may be contained within a package or pod using alayer, membrane, film, and the like so that the chemical divertercontained therein is released upon the package or pod dissolving orotherwise rupturing within the wellbore. Chemical diverters may be usedin linear, crosslinked, slick water, or acid hydraulic fracturingoperations.

The chemical components may be selected from benzoic acid, polyglycolicacid polymer, polylactic acid polymer, sodium chloride, oil-solubleresins, waxes, polyesters, poly carbonates, polyacetals, polyvinylchlorides, polyvinyl acetates, nylon, polytetrafluoroethylene, and anycombinations thereof. The chemical diverter particles may have anysuitable particle size effective to seal portions of the subterraneanformation. As an example, the chemical diverter particles may have aparticle size in the range of from 0.1 mm to less than 5 mm or from 0.1mm to 4 mm or from 0.5 mm to 2 mm. The particles may be flakes, pellets,beads, and the like.

Viscoelastic surfactants may be selected from cetyltrimethylammoniumbromide, cationic/anionic surfactant blends with a nonaqueous solvent,salicylic acid or phthalic acid with cationic or amphoteric surfactants,cationic surfactants such as erucyl methyl bis(2-hydroxyethyl) ammoniumchloride, 4-erucamidopropyl-1,1,1,-trimethyl ammonium chloride,zwitterionic/amphoteric surfactants such as oleylamidopropyl betaine,erucylamidepropy betaine, and anionic surfactants such as alkyl tauratesurfactants, methyl ester sulfonates, sulfosuccinates. Polymer gels maybe selected from hydroxyethylcellulose, acrylamide, polysaccharides suchas guar, xanthan, scleroglucan, and succinoglycan, and any combinationsthereof.

The metering device may include a pump, a motor, a source of storedenergy, and combinations thereof. The pump may be selected from a solidstate, piezoelectric pump, a positive displacement pump, or a hydraulicpump. As an example, the pump may be a solid state, piezoelectric pump.An example of a solid state, piezoelectric pump is described in U.S.Patent Publication No. 2015/0060083, titled “Systems and Methods forArtificial Lift Via a Downhole Piezoelectric Pump”, which description ofa piezoelectric pump is incorporated herein by reference. As anotherexample, the pump may be selected from a positive displacement pump or ahydraulic pump. It is understood that a positive displacement pump or ahydraulic pump may include an associated motor for the operation of thepump which is different from a motor acting as the primary component forthe metering device.

The motor as the primary component of the metering device may be anelectric motor. The electric motor may be powered by an alternatingcurrent (AC) voltage or a direct current (DC) voltage. As an example,the primary component of the metering device may be a brushless DCmotor.

The source of stored energy may include a stored energy device, such asa spring or pre-charged cylinder of a fluid, that may be operativelycoupled to the member within the sealing component holder, thusreplacing the need for a motor or a pump. The stored energy devices maybe operatively coupled to the member within the sealing component holdersimilar to a motor or pump, as further described herein.

Electrical power to the components of the metering device and othercomponents of the downhole device may be supplied locally or remotelyfrom the surface. A local source of electrical power may include one ormore batteries. The batteries may be positioned within the core andoperatively connected to the components of the metering device. Theremote source of power may be operatively connected to the downholedevice via an umbilical, as discussed in more detail herein, and/or aseparate electrical cable. Electrical connections from the batteries,the umbilical and/or the separate electrical cable may be providedwithin the core to connect the components of the metering device andother components of the downhole device requiring electricity to thesource of electrical power.

The metering device may be operatively connected to a member positionedwithin a sealing component holder such that, upon actuation of themetering device, the member displaces an internal volume of the sealingcomponent holder. As an example, FIG. 2 illustrates the member 184 maybe a bellow 175 having substantially the same cross-sectional dimensionas the sealing component holder 180 in which bellow 175 is positioned.The metering device 186 may be operatively connected to the bellow 175using a connection 179 constructed and arranged to deliver adisplacement fluid 183 from the displacement fluid storage 181 to aninlet 171 of the bellow 175 via the metering device 186 which may be apump 177, such as a solid state, piezoelectric pump. As illustrated inFIG. 2, the pump 177 is arranged transverse to the longitudinal axis ofthe downhole device 190; however, the pump 177 may have any suitableorientation within the core, such as parallel to the longitudinal axisof the downhole device. The displacement fluid 183 entering the inlet171 expands the bellow 175 to displace an internal volume of the sealingcomponent holder 180. The displacement fluid 183 may be any fluid havinga sufficient density capable of displacing an internal volume of asealing component holder.

As another example, the member may be a moveable bulkhead havingsubstantially the same cross-sectional dimensions as the sealingcomponent holder in which it is positioned forming a barrier between thebackside of the member and the sealing components. As an example, themetering device may be operatively connected to the member using aconnection including a mechanical actuator that may be longitudinallydisplaced to move the member within the sealing component holder todisplace an internal volume. The mechanical actuator may include apiston, a hydraulic cylinder, and any combinations thereof. Asillustrated in FIG. 8, member 184 is a moveable bulkhead 173 operativelyconnected to the metering device 186, which is pump 177, via connection188. Connection 188 may be attached to the back side 173B of bulkhead173. Connection 188 may include a piston 188A. Although not shown, ahydraulic cylinder may alternatively be included in connection 188. Thesealing components 182 may be positioned within the interior of thesealing component holder 180 between the opening 189 and the front side173A of bulkhead 173.

As another example, the metering device may be operatively connected tothe member using a conduit between a displacement fluid storage and aninlet port into the sealing component holder proximate the backside ofthe member and using the metering device to introduce the displacementfluid into the sealing component holder to move the member within thesealing component holder to displace an internal volume. FIG. 9 is aschematic representation of an operative connection between pump 177 asthe metering device 186 and an inlet port 185 which is in fluidcommunication with the back side 184B of member 184. Sealing componentsare not shown for clarity purposes. Connection 188 may include a conduit188B connecting a supply of displacement fluid 183 within thedisplacement fluid storage 181, pump 177 and inlet port 185. Member 184may include a sealing material 184C disposed on the outer surface ofmember 184 in contact with an inner surface of the sealing componentholder 180. The sealing components (not shown) may be positioned withinthe interior of the sealing component holder between the opening and thefront side 184A of the member 184.

As another example, the metering device may be operatively connected toa member which may be an auger. The metering device may be attached tothe auger in any suitable manner to be able to rotate the auger withinthe sealing component holder to displace an internal volume of thesealing component holder. FIG. 10 is a schematic representation of anoperative connection between a motor 174 as the metering device 186 andan auger 172 as member 184. Connection 188 includes a gear box 188C torotate and control the speed and torque of the rotation of auger 172 todisplace an internal volume of the sealing component holder 180 torelease sealing components (not shown) through the opening (not shown)in a surface of the core.

As another example, the metering device may be operatively connected toa member which may be moveable bulkhead. The metering device may be amotor and a ratcheting arrangement may be positioned between the motorand the bulkhead to displace an internal volume of the sealing componentholder. FIG. 11 is a schematic representation of an operative connectionbetween a motor 174 as the metering device 186 and moveable bulkhead 173as member 184. Connection 188 includes a ratcheting arrangement 188Dwhich provides longitudinal movement to connection 188 to displace aninternal volume of the sealing component holder 180 to release sealingcomponents through the opening. Although not shown in detail, theratcheting arrangement may include a ratchet wheel and a pawl and themotor is operatively coupled to the ratchet wheel and the ratchet wheelis operatively coupled with the pawl. The pawl is operatively coupledwith the connection rod to longitudinally move the rod forward todisplace the member within the sealing component holder.

As illustrated in FIG. 2, opening 189 may be positioned proximal thedistal (lower) end 109 of core 102. Alternatively, an opening 189 may bepositioned proximal the upper end 115 of the core. Alternatively,opening 189 may be positioned at any location along the length of thecore. If two or more sealing component holders are to be included withthe downhole device 190, the associated openings may be located atsubstantially the same axial length of the core but circumferentiallyoffset from each other or the associated openings may be located atsubstantially different axial lengths of the core and may or may not becircumferentially offset.

Referring to FIG. 2, the downhole device 190 may further include adetector 191. Detector 191 may be configured to detect any suitableproperty and/or parameter of downhole device 190, of fluid withintubular conduit 42, of wellbore tubular 40, and/or of tubular conduit 42(as illustrated in FIG. 1). As an example, detector 191 may beconfigured to detect a location of the downhole device 190 within thewellbore tubular 40.

An example of detector 191 includes a casing collar locator that isconfigured to detect, or count, casing collars of the wellbore tubularand monitor the relative length and relationship to one another. Thecasing collar locator may also be configured to locate any substantialvariation in casing components which may disturb magnetic lines fluxcoming from the casing components. Another example of detector 191includes a depth detector that is configured to detect a depth of thedownhole device within the tubular conduit. Yet another example ofdetector 191 includes a speed detector that is configured to detect aspeed of the downhole device within the tubular conduit. Another exampleof detector 191 includes a timer that is configured to measure a timeassociated with motion of the downhole device within the tubularconduit. Yet another example of detector 191 includes a downholepressure sensor that is configured to detect a pressure within the fluidthat is proximal thereto. Another example of detector 191 includes adownhole temperature sensor that is configured to detect a temperaturewithin the fluid that is proximal thereto.

Referring to FIG. 2, the downhole device 190 may further include acontroller 150 programmed to control the operation of the downholedevice, such as the metering device. The controller may include anysuitable structure. As an example, a controller may include and/or be aspecial-purpose controller, an analog controller, a digital controller,and/or a logic device. Communication linkage 108 may be included betweenthe metering device and the controller to provide a signal to themetering device to actuate the metering device and displace a giveninternal volume of the sealing component holder. Communication linkage108 may also be included between the controller 150 and a control system(not shown) located remotely at the surface. Communication linkage 108positioned within core 102 may be positioned within pass-through holes106, as illustrated in FIG. 2. The communications linkage 108 may beprovided via the umbilical, as discussed in more detail herein. Thecontroller may be programmed to receive actuation signals via theumbilical and provide actuation signals to the metering device.Alternatively, the controller may communicate with the metering deviceor the surface control system via a wireless communication network.Alternatively, the metering device may be controlled directly by thesurface control system via the umbilical and communications linkage orwireless communication network.

As an example, detector 191 may be configured to generate a locationsignal that is indicative of the location of the downhole device withinthe wellbore tubular and to convey the location signal to the controllervia communication linkage. In addition, the controller may be programmedto control the operation of the downhole device based, at least in part,on the location signal.

As another example, detector 191 may be configured to detect a shockwavegenerated within the wellbore conduit. Under these conditions, detector191 may generate a signal responsive to receipt of the shockwave and mayprovide the shockwave signal, via the communications linkage, to thecontroller or surface control system which in turn may generate a signalto actuate the metering device in response to the detected shockwave.

As another example, detector 191 may be configured to detect a pressurepulse within the wellbore fluid, such as may be deliberately and/orpurposefully generated within the wellbore fluid by an operator of thehydrocarbon well. Under these conditions, detector 191 may generate apressure pulse signal responsive to receipt of the pressure pulse andmay provide the pressure pulse signal, via the communications linkage,to the controller or surface control system.

In some embodiments, the downhole device may include additionalcomponents such that it may be used as a shockwave generation device.Shockwave generation devices may be used with systems and methods forstimulating a subterranean formation which include placing selectivestimulation ports (SSPs) within the wellbore tubular. Each SSP includesan isolation device that is configured to selectively transition from aclosed state to an open state responsive to the receipt of a shockwavehaving an intensity upon contact with the isolation device greater thana threshold shockwave intensity for the isolation device. The shockwavegeneration device may be utilized to provide the shockwaves toselectively transition the SSPs from a closed state to an open state topermit stimulation of a subterranean formation, such as subterraneanformation 34, and/or to permit an inrush of reservoir fluid into thewellbore tubular from the subterranean formation. Unlike perforationguns which detonate high energy shape-charges to form perforationswithin the wellbore tubular and the subterranean formation proximatethereto, the shockwave generation device requires much less energy sincethe device only has to generate the required shockwave intensity totransition the isolation device within the SSP to an open state. Unlikethe irregular perforations formed using a perforation gun, the SPPsprovide preformed openings of a controlled shape and may be made of amaterial that has a greater erosion-resistance, abrasion-resistance,and/or corrosion-resistance as compared to the material forming themajority of the wellbore tubular.

FIG. 12 is a schematic representation of a hydrocarbon well 10 that mayinclude and/or utilize a downhole device, in particular a shockwavegeneration device 190A, according to the present disclosure, to generatea shockwave 194 within a wellbore fluid 22 that extends within thetubular conduit 42. Wellbore tubular 40 of hydrocarbon well 10 includesa plurality of SSPs 100. SSPs 100 may be operatively attached to and/ormay form a portion of any suitable component of wellbore tubular 40.SSPs 100 may be configured to be operatively attached to and/or formedinto a portion of wellbore tubular 40 prior to the wellbore tubular 40being located, placed, and/or installed within wellbore 20.

SSPs 100 may be operatively attached to wellbore tubular 40 in anysuitable manner. As examples, SSPs 100 may be operatively attached towellbore tubular 40 via one or more of a threaded connection, a gluedconnection, a press-fit connection, a quarter turn latch connection, awelded connection, and/or a brazed connection.

Referring to FIGS. 12 and 13, shockwave generation device 190A may beconfigured to generate a shockwave 194 within a wellbore fluid 22 thatextends within tubular conduit 42. The shockwave propagates within thewellbore fluid and/or propagates from the shockwave generation device tothe SSP within and/or via the wellbore fluid. The shockwave may beattenuated by the wellbore fluid, and this attenuation may includeattenuation by at least a threshold attenuation rate. As an example, theshockwave may have a peak shockwave intensity proximal the shockwavegeneration device and may decay, or decrease in intensity, with distancefrom the shockwave generation device. Under these conditions, thethreshold shockwave intensity for an isolation device may be less than athreshold fraction of the peak shockwave intensity proximal theshockwave generation device. Examples of the threshold attenuation rateinclude attenuation rates of at least 1 megapascal per meter (MPa/m), atleast 2 MPa/m, at least 4 MPa/m, at least 6 MPa/m, at least 8 MPa/m, atleast 10 MPa/m, at least 12 MPa/m, at least 14 MPa/m, at least 16 MPa/m,at least 18 MPa/m, at least 20 MPa/m, and/or at least 30 MPa/m.

SSPs 100 are configured to selectively transition from a closed state,in which fluid flow there through (i.e., between the tubular conduit andthe subterranean formation) is blocked, restricted, and/or occluded, toan open state, in which fluid flow there through is permitted,responsive to receipt of, or responsive to experiencing, a shockwave ofgreater than a threshold shockwave intensity for the associatedisolation device of the SSP.

As an example, and as illustrated in FIGS. 12 and 14, SSPs 100 mayinclude an SSP body 110 that defines an SSP conduit 116 forming anopening within the wall of the wellbore tubular. SSP conduit 116 mayextend between tubular conduit 42 and subterranean formation 34. SSPbody 110 has a tubular conduit facing region 112 and an opposed,formation-facing region 114. SSP body 110 also has a projecting region113, which projects from SSP body 110 in a direction that is away fromor perpendicular to, a central axis 118 of SSP conduit 116. SSP mayinclude a tool-receiving portion 176, which may be configured to receivea tool during operative attachment of the SSP 100 to a wellbore tubular(not shown) and an attachment region 178, which may be configured tointerface with the wellbore tubular when the SSP 100 is operativelyattached to the wellbore tubular. As an example, attachment region 178may include threads (not shown), and SSP 100 may be configured to berotated, via receipt of the tool (not shown) within the tool-receivingportion 176, to permit threading of the SSP 100 into the wellboretubular. SSP 100 may further include a sealing component seat 140, whichmay be configured to receive a sealing component 182 when SSP istransitioned to an open state. Sealing component seat 140 may be shapedto form a fluid seal 144 with external surface 143 of sealing component182 when sealing component 182 is in sealing engagement with sealingcomponent seat 140 and SSP 100 is transitioned to an open state.

Sealing component seat 140 interfaces with tubular conduit 42 and may beshaped to form a fluid seal 144 with a sealing component 182, such as aball sealer, that flows into engagement with the sealing component seat140. Formation of the fluid seal 144 may selectively restrict fluid flowfrom tubular conduit 42 and into wellbore and/or subterranean formation34 via SSP conduit 116. Sealing component seat 140 may be a preformedsealing component seat that has a predetermined geometry prior towellbore tubular being located, placed, and/or installed withinwellbore. Sealing component seat 140 may be selected from acorrosion-resistant sealing component seat, an erosion-resistant sealingcomponent seat, an abrasion-resistant sealing component seat, and anycombinations thereof.

Referring to FIG. 14, SSPs 100 may further include an isolation device120 which is illustrated in a closed state 121. SSP 100 may also includeretention device 130. Retention device 130 may be configured to couple,or operatively couple, isolation device 120 to SSP body 110, such as toretain the isolation device 120 in the closed state 121 prior to receiptof a shockwave having an intensity greater than a threshold shockwaveintensity for the isolation device 120 transitioning SSP 100 to an openstate (not shown).

As an example, isolation device 120 may include an isolation disk thatextends across SSP conduit 116 when the SSP 100 is in the closed stateand that separates from SSP body 110 responsive to receipt of theshockwave with greater than the threshold shockwave intensity, such asto permit fluid flow through SSP conduit 116 when the SSP 100 is in theopen state. As another example, isolation device 120 may include afrangible isolation disk that extends across SSP conduit 116 when theSSP 100 is in the closed state and that breaks apart responsive toreceipt of the shockwave with greater than the threshold shockwaveintensity, such as to permit fluid flow through SSP conduit 116 when theSSP 100 is transitioned to the open state.

Since shockwave 194 is attenuated by wellbore fluid 22, the shockwavemay have sufficient energy (i.e., may have greater than the thresholdshockwave intensity for an isolation device) to transition a first SSP100, which is less than a threshold distance from the shockwavegeneration device 190A when the shockwave generation device 190Agenerates the shockwave 194, from the closed state to the open state.However, the shockwave 194 may have insufficient energy to transition asecond SSP 100, which is greater than the threshold distance from theshockwave generation device when the shockwave generation devicegenerates the shockwave, and remains in the closed state.

Stated another way, the plurality of explosive charges may be sized suchthat the shockwave selectively transitions the first SSP from the closedstate to the open state but does not transition the second SSP from theclosed state to the open state. The threshold distance also may bereferred to herein as a maximum effective distance of the shockwaveand/or of the shockwave generation device 190A from which the shockwavewas generated. Examples of the threshold distance include thresholddistances of less than 1 meter, less than 2 meters, less than 3 meters,less than 4 meters, less than 5 meters, less than 6 meters, less than 7meters, less than 8 meters, less than 10 meters, less than 15 meters,less than 20 meters, or less than 30 meters along an axial length of thetubular conduit.

Shockwave generation device 190A may include and/or be any suitablestructure that may, or may be utilized to, generate a shockwave 194within wellbore fluid 22. The shockwave generation device 190A may be anumbilical-attached downhole device or an autonomous downhole device, asdiscussed in more detail herein.

FIG. 13 is a schematic representation of a shockwave generation device190A for deployment within hydrocarbon well 10 according to the presentdisclosure, while FIG. 15 is a more detailed but still schematicrepresentation of a portion of the shockwave generation device 190A ofFIG. 13. FIG. 16 is a less detailed schematic side view of a shockwavegeneration device 190A according to the present disclosure, while FIG.17 is a cross-sectional view of a shockwave generation device 190Aillustrating various relative shapes and orientations for flutes,explosive charges, and protective barriers that may be utilized inshockwave generation devices 190A. FIG. 18 is a less detailed schematicside view of a shockwave generation device 190A according to the presentdisclosure, while FIG. 19 is a cross-sectional view of the shockwavegeneration device 190A of FIG. 18 taken along line 7-7 of FIG. 18. FIG.20 illustrates various transverse cross-sectional shapes for flutes thatmay be defined by the core of a shockwave generation device 190Aaccording to the present disclosure.

Any of the structures, functions, and/or features that are discussedherein with reference to shockwave generation devices 190A of FIGS. 13and 15-20 may be included in and/or utilized with downhole device 190Aand/or hydrocarbon well 10 of FIG. 12 without departing from the scopeof the present disclosure. Similarly, any of the structures, functions,and/or features that are discussed herein with reference to downholedevice 190 and/or hydrocarbon well 10 of FIG. 1 may be included inand/or utilized with shockwave generation devices 190A of FIGS. 13 and15-20 without departing from the scope of the present disclosure.

As illustrated in FIG. 23, shockwave generation device 190A isconfigured to generate shockwave 194 within wellbore fluid 22 thatextends within tubular conduit 42 of wellbore tubular 40. As illustratedin FIG. 13, shockwave generation device 190A includes core 500 and aplurality of explosive charges 520. Shockwave generation device 190Afurther includes a plurality of triggering devices 530.

Explosive charges 520 are arranged on an external surface 502 of core500, and each triggering device 530 is configured to initiate explosionof a selected one of the plurality of explosive charges 520. Statedanother way, shockwave generation device 190A may be configured suchthat a selected triggering device 530 may initiate explosion of aselected explosive charge 520 without initiating explosion of otherexplosive charges 520 that may be associated with other triggeringdevices 530. As such, shockwave generation device 190A also may bereferred to herein as, or may be, a select-fire, shockwave generationdevice 190A, a selective-fire, downhole shockwave generation device190A, and/or a shockwave generation device 190A that is configured toselectively explode a plurality of explosive charges 520 and to generatea plurality of shockwaves that are spaced-apart in time.

It is within the scope of the present disclosure that the phrase“selected one of the plurality of explosive charges” may refer to asingle explosive charge 520. Alternatively, it is also within the scopeof the present disclosure that the phrase “selected one of the pluralityof explosive charges” may refer to two or more spaced-apart, separate,and/or distinct explosive charges 520 and also may be referred to hereinas a selected portion of the plurality of explosive charges. Thus, agiven triggering device 530 may initiate explosion of a single explosivecharge 520 or two or more of the plurality of explosive charges 520within a selected portion of the plurality of explosive charges 520.Regardless of the exact configuration, each triggering device 530 mayinitiate explosion of one or more selected and/or predeterminedexplosive charges 520 but may not initiate explosion of each, or every,explosive charge that is included within shockwave generation device190A.

Shockwave generation device 190A may be configured such that theshockwave emanates symmetrically, at least substantially symmetrically,isotropically, and/or at least substantially isotropically, therefrom.Stated another way, the shockwave generation device may be configuredsuch that the shockwave is symmetric, at least substantially symmetric,isotropic, and/or at least substantially isotropic within a giventransverse cross-section of the wellbore tubular in which the shockwavein generated. This symmetric and/or isotropic behavior of the shockwavemay be accomplished in any suitable manner. As an example, and asdiscussed in more detail herein, explosive charges 520 may becircumferentially wrapped around, or at least substantially around, anexternal surface 502 of core 500.

Core 500 of shockwave generation device 190A may be a core as discussedin more detail herein with respect to a downhole device and may includeany suitable structure and/or material that may have, form, and/ordefine external surface 502, which may also support explosive charges520, and/or triggering devices 530. It is also within the scope of thepresent disclosure that core 500 may have and/or define one or morepass-through holes 506, as illustrated in FIG. 13. Pass-through holes506 may extend along a longitudinal length of core 500, andcommunication linkage 508 may extend therein, as illustrated in FIGS. 13and 15. Communication linkage 508 may permit and/or providecommunication between one or more components of shockwave generationdevice 190A and/or between umbilical 192 and one or more components ofshockwave generation device 190A and/or between wireless communicationnetwork 39 (as illustrated in FIG. 12) and one or more components of theshockwave generation device 190A. Although not shown, pass-through holes506 may also be provided along a longitudinal length of core 500 toaccommodate electrical connections between one or more components of theshockwave generation device 190A and the source of electrical powerand/or between components of the shockwave generation device 190A. It isunderstood that pass-through holes, communications linkage andelectrical connections may also be included with downhole device 190.

As illustrated in FIG. 13, core 500 may further have, include, and/ordefine one or more flutes 504. Flutes 504 may be defined by externalsurface 502. In addition, flutes 504 may be shaped and/or configured toreceive and/or contain one or more explosive charges 520. As an example,each flute 504 may receive and/or contain at least a portion, amajority, or even an entirety, of a respective one of the plurality ofexplosive charges 520.

As illustrated in FIGS. 17 and 20, each flute 504 includes a respectiverecess 512 and a respective opening 514. Both the opening and the recessare defined by core 500, and the opening provides, or is sized toprovide, access to the recess by a given explosive charge 520. Recesses512 may include and/or be elongate recesses that may extend along thelongitudinal length of core 500, that may extend about and/or aroundcore 500, that may spiral around core 500, and/or that may extendcircumferentially around a transverse cross-section of core 500.Similarly, openings 514 may include and/or be elongate openings that mayextend along the longitudinal length of core 500, that may extend aboutand/or around core 500, that may spiral around core 500, and/or that mayextend circumferentially around a transverse cross-section of core 500.

As an example, and as illustrated in FIGS. 13 and 15 flutes 504 mayextend longitudinally along the longitudinal length of core 500. Asanother example, and as illustrated in FIG. 16, flutes 504 may include aplurality of spiraling flutes that wrap around external surface 502and/or that spirals along a longitudinal axis of core 500. As yetanother example, and as illustrated in FIGS. 18 and 19, flutes 504 mayinclude a plurality of circumferential flutes that extends at leastpartially, or even completely, around the transverse cross-section ofthe core and may include corresponding circumferential explosive charges520.

It is within the scope of the present disclosure that flutes 504 may atleast partially, or even completely, house and/or contain respectiveexplosive charges 520. As an example, and as illustrated in FIG. 17 at515, a respective explosive charge 520 may extend within recess 512 andmay not extend and/or project through and/or across opening 514. Statedanother way, a given explosive charge may have and/or define arespective transverse cross-sectional area, a given flute, whichreceives the given explosive charge, may have and/or define a respectivetransverse cross-sectional area, and the respective transversecross-sectional area of the given explosive charge may be less than therespective transverse cross-sectional area of the given flute.

Such a configuration may be utilized to protect the explosive chargefrom damage due to motion of the shockwave generation device within thetubular conduit and/or due to flow of an abrasive material past theshockwave generation device while the shockwave generation device ispresent within the tubular conduit. Additionally or alternatively, sucha configuration may provide a desired level of focusing, a desiredintensity, and/or a desired directionality of the shockwave that isgenerated responsive to explosion of the given explosive charge.

A given flute 504 additionally or alternatively may be shaped and/orotherwise configured to protect a given explosive charge 520 such thatinitiation of explosion of another, or an adjacent, explosive charge 520does not initiate explosion of the given explosive charge 520. Asexamples, the given flute 504 may direct the shockwave that is generatedby given explosive charge 520 away from core 500, may direct theshockwave away from the other flutes 504, and/or may direct theshockwave away from other explosive charges 520 that are associated withthe other flutes 504. As additional examples, the given flute 504 and/orthe adjacent flute(s) may be configured to sufficiently shield and/orisolate the adjacent explosive charges from the shockwave produced bythe given explosive charge 520 to prevent the shockwave from the givenexplosive charge initiating explosion of the adjacent explosive charges.Such configurations may permit and/or facilitate each triggering device520 to initiate explosion of one or more selected explosive charges 520without initiating explosion of each, or every, explosive charge that isincluded within shockwave generation device 190A.

As another example, and as illustrated in FIG. 17 at 516, a respectiveexplosive charge 520 may extend within recess 512 and also may extendand/or project through and/or across opening 514. Stated another way,the respective transverse cross-sectional area of the given charge maybe less than the respective transverse cross-sectional area of the givenflute. Such a configuration may provide a desired level of focusing, adesired intensity, and/or a desired directionality of the shockwave thatis generated responsive to explosion of the given explosive charge.

It is within the scope of the present disclosure that flutes 504 mayhave and/or define any suitable cross-sectional, or transversecross-sectional, shape. As an example, and as illustrated in FIG. 20 at590, flutes 504 may have and/or define a circular, or at least partiallycircular, transverse cross-sectional shape. As another example, and asillustrated in FIG. 20 at 592, flutes 504 may have and/or define anarcuate, or at least partially arcuate, transverse cross-sectionalshape. As yet another example, and as illustrated in FIG. 20 at 594,flutes 504 may have and/or define a triangular, at least partiallytriangular, V-shaped, or at least partially V-shaped, transversecross-sectional shape. As another example, and as illustrated in FIG. 20at 596, flutes 504 may have and/or define a square, at least partiallysquare, rectangular, or at least partially rectangular, transversecross-sectional shape. Flutes with other regular and/or irregulargeometric transverse cross-sectional shapes also may be utilized. Asillustrated in FIG. 20 at 598, one or more explosive charges 520 mayextend across a portion of external surface 502 that does not include aflute.

As discussed in more detail herein, core 500 may be a single-pieceand/or monolithic structure or, alternatively, a multi-piece core thatincludes a plurality of core segments 510 as illustrated in FIG. 18.Each core segment 510 may be operatively attached to one or moreadjacent core segments to form and/or define core 500. It is understoodsuch arrangements of core 500 may also be utilized with core 102 ofdownhole device 190. When shockwave generation device 190A includes coresegments 510, it is within the scope of the present disclosure that eachcore segment 510 may have any suitable number of explosive charges 520and/or corresponding triggering devices 530 associated therewith and/orattached thereto. As examples, each core segment may have 1, 2, 3, 4, 5,6, 7, 8, or more than 8 explosive charges and/or correspondingtriggering devices associated therewith and/or attached thereto. Whenshockwave generation device 190A includes core segments 510, it iswithin the scope of the present disclosure that a core segment at thedistal end of the core may form the sealing component holder.Additionally or alternatively, one or more of the core segments 510 mayinclude an internal void such that when such core segments 510 areoperatively attached, a sealing component holder 180 may be formedwithin the interior of the defined core 500; at least one of the coresegments 510 may include an opening 189 to the so formed sealingcomponent holder 180 with an associated cover (not shown); and at leastone of the core segments 510 includes all or a portion of the meteringdevice (not shown). If a plurality of sealing component holders are tobe included within core 500, additional sealing component holders may besimilarly formed.

Explosive charges 520 may include and/or be any suitable structure thatmay be adapted, configured, formulated, synthesized, and/or constructedto selectively explode and/or to selectively generate the shockwavewithin the wellbore fluid without causing substantial damage to theshockwave generation device during intended operations. Stated anotherway, at most only insubstantial damage may be experienced by theshockwave generation device upon exploding explosive charges 520 duringintended operation of the device.

An example of explosive charges 520 include a primer cord (or detonationcord) 522. As an example, shockwave generation device 190A may include aplurality of lengths of primer cord 522, with each explosive charge 520including at least one length of primer cord as the source of explosiveon the shockwave generation device 190A. Primer cord 522 also may bereferred to as detonation cord or detonating cord and configured toexplode and/or detonate. The primer cord may be any suitable length. Asexamples, the length of the primer cord may be at least 0.1 meter (m),at least 0.2 m, at least 0.3 m, at least 0.4 m, at least 0.5 m, at least0.6 m, at least 0.7 m, at least 0.8 m, at least 0.9 m, at least 1 m, atleast 1.25 m, at least 1.5 m, at least 1.75 m, or at least 2 m.Additionally or alternatively, the length of the primer cord may be lessthan 5 m, less than 4.5 m, less than 4 m, less than 3.5 m, less than 3m, less than 2.5 m, less than 2 m, less than 1.5 m, or less than 1 m.

Primer cord 522 also may include any suitable amount of an explosive,such as research department formula X (RDX), high melting explosive(HMX), or hexanitrostilbene (HNS). HMX may also be referred to asoctogen, her majesty's explosive, high velocity military explosive, orhigh molecular weight RDX. As examples, the primer cord may include atleast 10 grains of explosive per foot of length (grains/ft) (or 2 gramsper meter (g/m)), at least 20 grains/ft (or 4 g/m), at least 25grains/ft (or 5 grams per meter (g/m)), at least 40 grains/ft (or 8grams per meter (g/m)), at least 80 grains/ft (or 17 g/m), at least 100grains/ft (or 21 grams per meter (g/m)), at least 160 grains/ft (or 34grams per meter (g/m)), or at least 240 grains/ft (or 51 grams per meter(g/m)). Additionally or alternatively, the primer cord may include lessthan 1000 grains/ft (212 g/m), less than 720 grains/ft (153 g/m), lessthan 560 grains/ft (or 119 grams per meter (g/m)), less than 500grains/ft (or 106 grams per meter (g/m)), less than 450 grains/ft (or 96grams per meter (g/m)), less than 480 grains/ft (or 102 grams per meter(g/m)), less than 400 grains/ft (85 g/m), or less than 320 grains/ft (68g/m). The amount of explosive may be in the range of from 20 grains/ft(4 g/m) to 1000 grains/ft (212 g/m), or from 25 grains/ft (5 g/m) to 560grains/ft (119 g/m) or from 50 grains/ft (10 g/m) to 480 grains/ft (102g/m). It is also understood that isolation devices may be used withinthe SSPs which may be made of stronger materials and may require largerexplosive charges to open the SSP and/or Such SSPs may be installedwithin a wellbore tubular that has a greater pipe weight and/or is madeof a stronger metal than typical wellbore tubulars in which caseexplosive concentrations may be in excess of 1000 grains/ft (212 g/m),of 2000 grains/ft (425 g/m), or of 3000 grains/ft (638 g/m).

In general, the length of the primer cord and/or the amount of explosiveper unit length of the primer cord may be selected to provide a desiredintensity, or a desired maximum intensity, for the shockwave when theprimer cord explodes within the wellbore fluid. As an example, thelength of the primer cord and/or the amount of explosive per unit lengthof the primer cord may be selected such that the maximum intensity ofthe shockwave is greater than the threshold shockwave intensitynecessary to transition an SSP from the closed state to the open state.As another example, the length of the primer cord and/or the amount ofexplosive charge per unit length of the primer cord may be selected suchthat maximum intensity of the shockwave is less than an intensity thatwould damage, or rupture, a wellbore tubular that defines a tubularconduit within which the shockwave is generated and/or such that theshockwave has insufficient energy, or intensity, to rupture or damagethe wellbore tubular.

Stated another way, each explosive charge 520 may be sized such that theshockwave has a maximum pressure of at least 100 megapascals (MPa), atleast 110 MPa, at least 120 MPa, at least 130 MPa, at least 140 MPa, atleast 150 MPa, at least 160 MPa, at least 170 MPa, at least 180 MPa, atleast 190 MPa, at least 200 MPa, at least 250 MPa, at least 300 MPa, atleast 400 MPa, or at least 500 MPa. Additionally or alternatively, eachexplosive charge 520 may be sized such that the shockwave has a maximumduration of less than 1 second, less than 0.9 seconds, less than 0.8seconds, less than 0.7 seconds, less than 0.6 seconds, less than 0.5seconds, less than 0.4 seconds, less than 0.3 seconds, less than 0.2seconds, less than 0.1 seconds, less than 0.05 seconds, or less than0.01 seconds. The maximum duration may be a maximum period of timeduring which the shockwave within the wellbore tubular has greater thanthe threshold shockwave intensity for the isolation device. Additionallyor alternatively, the maximum duration may be a maximum period of timeduring which the shockwave has a shockwave intensity of greater than68.9 MPa (10,000 pounds per square inch) within the portion of thewellbore tubular proximal the SSP to be transitioned from the closedstate to the open state.

Each explosive charge 520 may be sized such that the shockwave withinthe tubular conduit exhibits a shockwave intensity greater than thethreshold shockwave intensity for an isolation device over a maximumeffective distance or length along the tubular conduit. Examples of themaximum effective distance are as discussed in more detail herein.

Shockwave generation device 190A may include any suitable number ofexplosive charges 520. As examples, the shockwave generation device mayinclude at least 2, at least 3, at least 4, at least 5, at least 6, atleast 7, or at least 8 explosive charges. Additionally or alternatively,the shockwave generation device may include 20 or fewer, 18 or fewer, 16or fewer, 14 or fewer, 12 or fewer, 10 or fewer, 8 or fewer, 6 or fewer,or 4 or fewer explosive charges.

Triggering devices 530 may include and/or be any suitable structure thatmay be configured to selectively initiate explosion of a selectedportion of the plurality of explosive charges independent from aremainder of the explosive charges. As an example, triggering devices530 may include and/or be electrically actuated triggering devices,separately addressable switches, and/or detonators 532, as illustratedin FIG. 15. Detonators may include blasting caps. As a more specificexample, each triggering device 530 may include a uniquely addressableswitch that may be configured to initiate explosion of a selected one ofthe plurality of explosive charges responsive to receipt of a uniquecode. The unique code of each triggering device may be different fromthe unique code of each of the other triggering devices, therebypermitting selective actuation of a given triggering device.

As illustrated in FIGS. 13, 15-16, and 18, triggering devices 530 mayform a portion of a triggering assembly 528. Triggering assembly 528 maybe operatively attached to core 500 and/or may form a portion of core500. In addition, and when shockwave generation device 190A is submergedwithin the wellbore fluid, triggering assembly 528 may at leastpartially, or even completely, isolate at least a portion, or even all,of each triggering device 530 from the wellbore fluid. As an example,and as illustrated in FIGS. 13 and 15, triggering assembly 528 mayinclude and/or define an enclosed volume 529 within the core 500 that isfluidly isolated from the wellbore fluid and/or that contains and/orhouses the triggering devices.

As illustrated in FIGS. 13, 15, 17, and 19, shockwave generation device190A and/or explosive charge 520 thereof may further include aprotective barrier 524. Protective barrier 524 may be configured to atleast partially, or even completely, isolate, or fluidly isolate,explosive charges 520 from the wellbore fluid when the shockwavegeneration device is submerged within the wellbore fluid. Such isolationmay prevent contamination of the explosive charge by the wellbore fluid,may prevent degradation of the explosive charge by the wellbore fluid,may resist permeation of the wellbore fluid into the explosive charge,and/or may resist abrasion of the explosive charge from movement withinthe wellbore or by an abrasive material, such as a proppant, that may bepresent within the wellbore fluid and/or by wellbore tubular when theshockwave generation device is present within tubular conduit.

As illustrated in FIG. 13, protective barrier 524 may extend along alength, or even an entire length, of explosive charge 520. Asillustrated in FIG. 17 at 525, protective barrier 524 may extendcompletely around a transverse cross-section of a given explosive charge520. Additionally or alternatively, and as illustrated in FIG. 17 at526, protective barrier 524 may extend at least partially around atransverse cross-section of core 500 and/or of external surface 502thereof and of a given explosive charge 520.

It is within the scope of the present disclosure that shockwavegeneration device 190A may include a plurality of protective barriers524 and that each protective barrier 524 may extend around acorresponding explosive charge 520, may extend along a length of thecorresponding explosive charge, may extend along an entirety of thelength of the corresponding explosive charge, and/or may extend across arespective portion of external surface 502 of core 500 to protect theexplosive charge 520 from damage during movement within the wellbore orparticle flow around the shockwave generation device 190A. Additionallyor alternatively, it is also within the scope of the present disclosurethat a single protective barrier 524 may extend at least partiallyaround two or more of the explosive charges and/or may extend across amajority, or even all, of external surface 502 of core 500. Protectivebarrier 524 may include and/or be formed from any suitable material. Asexamples, the protective barrier may include and/or be a non-metallicprotective barrier and/or may be formed from a polymeric material, anelastomeric material, and/or a resilient material.

As illustrated in FIGS. 13 and 15, shockwave generation device 190A mayinclude a first plurality of explosive charges 520 and a correspondingfirst plurality of triggering devices 530. In addition, and asillustrated in FIGS. 13 and 15, shockwave generation device 190A alsomay include a second plurality of explosive charges 520 and acorresponding second plurality of triggering devices 530. The firstplurality of explosive charges and the first plurality of triggeringdevices together may define a first shockwave generation unit 198 (asindicated in solid lines), and the second plurality of explosive chargesand the second plurality of triggering devices together may define asecond shockwave generation unit 198 (as indicated in dashed lines). Anadditional section 199 is included at the distal end of the shockwavegeneration device 190A and includes the sealing component holder andmetering device.

The first shockwave generation unit and the second shockwave generationunit may be operatively attached to one another, in an end-to-endfashion, to form and/or define shockwave generation device 190A. As anexample, an end region of the first shockwave generation unit may beoperatively attached to an end region of the second shockwave generationunit, such as via a coupling structure 562 and/or such that alongitudinal axis of the first shockwave generation unit is aligned, orat least substantially aligned, with a longitudinal axis of the secondshockwave generation unit. Shockwave generation device 190A may includeany suitable number of shockwave generation units 198 and each shockwavegeneration unit 198 may include any suitable number of explosive charges520 and corresponding triggering devices 530. As examples, shockwavegeneration device 190A may include at least 2, at least 3, at least 4,at least 5, at least 6, at least 8, or at least 10 shockwave generationunits. At least the lowermost (downhole direction) portion of shockwavegeneration device 190A may include a sealing component holder section199. Section 199 may form a portion of the lowermost shockwavegeneration unit 198 or may form a separate unit such that an end regionof the first shockwave generation unit may be operatively attached to anend region of the sealing component holder unit, such as via a couplingstructure (not shown) and/or such that a longitudinal axis of the firstshockwave generation unit is aligned, or at least substantially aligned,with a longitudinal axis of the sealing component holder unit.

Shockwave generation device 190A may be adapted, configured, designed,constructed, and/or sized to remain in the tubular conduit duringstimulation of the subterranean formation, during flow of a stimulantfluid through and/or within the tubular conduit and past the shockwavegeneration device 190A, and/or during the inrush of reservoir fluid intothe wellbore tubular. Shockwave generation device 190A may have anysuitable length or overall length. As examples, the overall length ofthe shockwave generation device may be less than 40 meters, less than 35meters, less than 30 meters, less than 25 meters, or less than 20meters. The shockwave generation device 190A also may have any suitablemaximum transverse cross-sectional extent, dimension, and/or diametersuitable for deployment within a wellbore tubular. As examples, themaximum transverse cross-sectional extent, dimension, and/or diametermay be less than 0.2 meters (m), less than 0.15 m, less than 0.1 m, lessthan 0.8 m, less than 0.09 m or less than 0.06 m. It is understood thata downhole device without the shockwave generation features may havesimilar dimensions.

The maximum transverse cross-sectional inner diameter of the tubularconduit and/or wellbore tubular may be any suitable diameter capable ofaccommodating the downhole device and any other downhole equipmentand/or downhole components. As an example, the maximum transversecross-sectional inner diameter of the tubular conduit and/or wellboretubular may be in the range of from 70 mm to 178 mm or from 90 mm to 105mm or from 94 mm to 102 mm. In such example, opening 189 may be providedproximal the distal end 109 of the shockwave generation device 190Aand/or downhole device 190 and the sealing components 182 may includeoversized ball sealers as discussed in more detail herein. As anexample, the opening 189 may be provided in a bottom surface of theshockwave generation device 190A and/or downhole device 190. As anotherexample, the opening 189 may be provided in a side surface having alesser transverse cross-section dimension or diameter than the averagetransverse cross-sectional dimension or diameter of the shockwavegeneration device 190A and/or downhole device 190, as determined alongits length, such that the sealing components (e.g., ball sealers) do nothave to pass between the wellbore tubular and the maximum transversecross-section extent, dimension and/or diameter of device 190, 190A.This arrangement provides the ability to locally release oversized ballsealers at different spaced-apart sections of the wellbore, oversizedball sealers having a maximum outer dimension larger than the gap formedbetween the wellbore tubular and the maximum outer dimension of theshockwave generation device or downhole device. Additionally oralternatively, when an opening 189 is positioned at other side surfacelocations along the length of the shockwave generation device 190A ordownhole device 190, the maximum transverse cross-sectional dimension ofthe shockwave generation device 190A or downhole device 190 may be lessthan a cross-sectional diameter of the tubular conduit such that a gapformed there between may have a sufficient radial dimension to provideclearance for flow of the sealing components past the shockwavegeneration device 190A or downhole device 190.

As illustrated in FIGS. 13 and 15, shockwave generation device 190A mayfurther include a detector 540. Detector 540 may be similar to detector191 as discussed in more detail herein. Another example of detector 540includes a magnetic field detector that is configured to detect amagnetic field that emanates from a magnetic material that defines aportion of the wellbore tubular and/or a SSP of the wellbore tubular.Yet another example of detector 540 includes a radioactivity detectorthat is configured to detect a radioactive material that forms and/ordefines a portion of the wellbore tubular and/or a SSP 100 of thewellbore tubular. Yet another example of detector 540 includes adownhole pressure sensor that is configured to detect a pressure withinthe wellbore fluid that is proximal thereto. Another example of detector540 includes a downhole temperature sensor that is configured to detecta temperature within the wellbore fluid.

As illustrated in FIGS. 13 and 15, shockwave generation device 190A mayfurther include a controller 550. Controller 550 may be adapted,configured, designed, constructed, and/or programmed to control theoperation of at least a portion of the shockwave generation device 190A.Controller 550 may include any suitable structure, as discussed in moredetail herein with respect to controller 150. As an example, controller150 may be used to actuate metering device 186 and controller 550 may beused to actuate a triggering device 530. Control by controller 550 maybe based, at least in part, on a property and/or parameter detected bydetector 540. Control by controller 150 may be based, at least in part,on a property and/or parameter detected by detector 191. As an example,and as illustrated in FIG. 15, shockwave generation device 190A mayinclude communication linkage 552 between controller 550 and detector540.

As an example, detector 540 may be configured to generate a locationsignal that is indicative of the location of the shockwave generationdevice 190A within the wellbore tubular 40 and to convey the locationsignal to the controller 550 via the communication linkage 552. Inaddition, controller 550 may be programmed to actuate the meteringdevice (instead of using a separate controller 150) and/or a selectedone of the plurality of triggering devices 530 based, at least in part,on the location signal and/or responsive to receipt of the locationsignal. Metering device 186 may displace an internal volume of thesealing component holder or triggering device 530 then may initiateexplosion of a corresponding one of the plurality of explosive charges520. Detector 540 may be used alternatively or in addition to detector191.

As another example, detector 540 may be configured to detect a pressurepulse within the wellbore fluid, such as may be deliberately and/orpurposefully generated within the wellbore fluid by an operator of thehydrocarbon well. Under these conditions, detector 540 may generate apressure pulse signal responsive to receipt of the pressure pulse andmay provide the pressure pulse signal, via the communication linkage, tocontroller 550. Controller 550 then may be programmed to actuate themetering device and/or the selected one of the plurality of triggeringdevices 530 based, at least in part, on the pressure pulse signal and/orresponsive to receipt of the pressure pulse signal.

Additionally or alternatively, controller 550 may be configured toactuate the metering device and/or the selected one of the plurality oftriggering devices responsive to receipt of an actuation signal and/or atriggering signal. The signal may be provided to the controller in anysuitable manner. As an example, the signal may be provided to controller550 using downhole wireless communication network 39, and controller 550may be adapted, configured, designed, constructed, and/or programmed toreceive the signal from the downhole wireless communication network. Asanother example, the signal may be provided to controller 550 usingumbilical 192. Under these conditions, controller 550 may be adapted,configured, designed, constructed, and/or programmed to receive thesignal from the umbilical, and it is within the scope of the presentdisclosure that the umbilical may be configured to provide serialcommunication between the controller and surface region 30.Alternatively, the devices may be controlled directly by the surfacecontrol system via the umbilical and communications linkage or wirelesscommunication network.

The shockwave generation device 190A may further include a guidestructure (not shown). The guide structure may be adapted, configured,sized, and/or shaped to passively guide and/or direct the shockwavegeneration device when the shockwave generation device moves and/ortranslates within the tubular conduit. It is understood that such guidestructure may be used with a downhole device without the shockwavegeneration features.

Shockwave generation device 190A may include a bridge plug settingstructure (not shown) in embodiments where the opening to the sealingcomponent holder is positioned at a surface location other than thebottom surface of the shockwave generation device. A bridge plug settingstructure may be configured to set, or to selectively set, a bridge plugwithin the tubular conduit. It is understood that such plug settingstructure may be used with a downhole device without the shockwavegeneration features.

As also illustrated in FIG. 13, shockwave generation device 190Aincludes the components of the downhole device 190. Such components aredepicted in the figures with the same reference numbers as for downholedevices 190. Sealing component holder 180 and metering device 186 may beconfigured to selectively release at least one sealing component, suchas a ball sealer, for each explosive charge 520 that is associated withshockwave generation device 190A and/or for each SSP that is opened byeach explosive charge. This may include releasing the at least onesealing component 182 responsive to explosion of a correspondingexplosive charge 520, prior to explosion of the corresponding explosivecharge, and/or subsequent to explosion of the corresponding explosivecharge. It is intended that the description contained herein withrespect to sealing component holders, sealing components, meteringdevices, and arrangements including such for downhole device 190 mayalso be utilized with shockwave generation device 190A.

As illustrated in FIG. 13, shockwave generation device 190A may furtherinclude and/or have operatively attached thereto one or more weights564. Weights 564 may be configured to increase an average density of theshockwave generation device, to increase a weight of the shockwavegeneration device, and/or to regulate an orientation of the shockwavegeneration device when the shockwave generation device is present withinthe tubular conduit. As an example, and as illustrated in FIG. 13,weight 564 may be oriented off-center with respect to (parallel to) thelongitudinal axis of shockwave generation device 190A and thereby maycause the shockwave generation device to orient within the tubularconduit in a predetermined, or desired, manner. It is understood thatsuch weights may be used with a downhole device without the shockwavegeneration features.

It is within the scope of the present disclosure that, subsequent toactuation of all the explosive charges 520, shockwave generation device190A may be adapted, configured, designed, and/or constructed to breakapart and/or to dissolve within the tubular conduit. As an example,shockwave generation device 190A may be formed from a frangible materialthat breaks apart responsive to explosion of a last, or final, explosivecharge 520. It is understood that a downhole device without theshockwave generation features may be similarly constructed.

As another example, shockwave generation device 190A may be formed froma degradable material that degrades within the wellbore fluid. This mayinclude degrading within a timeframe that is shorter than a timeframefor other components of the hydrocarbon well, such as wellbore tubular40. As an example, the shockwave generation device 190A may beconfigured to remain intact during generation of the shockwaves and topartially degrade, completely degrade, and/or break apart betweencompletion of stimulation operations that utilize the shockwavegeneration device and production of reservoir fluid from the hydrocarbonwell. It is understood that a downhole device without the shockwavegeneration features may be similarly constructed.

As yet another example, shockwave generation device 190A may be formedfrom a soluble material that is soluble within the wellbore fluid. Thissoluble material may be selected to dissolve within a timeframe that isshorter than the timeframe for other components of the hydrocarbon well,such as wellbore tubular 40, to degrade and/or break apart. As anexample, the shockwave generation device may be configured to remainintact during generation of the shockwaves and to dissolve, completelydissolve, and/or break apart between completion of stimulationoperations that utilize the shockwave generation device and productionof reservoir fluid from the hydrocarbon well. It is understood that adownhole device without the shockwave generation features may besimilarly constructed.

FIG. 21 is a flowchart depicting method 800, according to the presentdisclosure, which includes providing sealing components within a tubularconduit and optionally also generating a plurality of shockwaves withina wellbore fluid that extends within the tubular conduit, while FIGS.22-26 are schematic cross-sectional views of a portion of a process flow340 for providing sealing components and optionally generating aplurality of shockwaves 194 within a tubular conduit 40. As illustratedin process flow 340 of FIGS. 22-26, a shockwave generation device 190Amay be positioned within a wellbore tubular 40 that defines a tubularconduit 42 and extends within subterranean formation 34. The wellboretubular may include a plurality of SSPs 100 that initially may be in aclosed state. The plurality of SSPs 100 may be spaced apart along thewellbore tubular, such as along the longitudinal length of the wellboretubular and/or radially around the circumference of the wellboretubular.

Method 800 may include pressurizing the tubular conduit by introducing awellbore fluid, such as a stimulant fluid, at 805 and includespositioning a downhole device, such as a shockwave generation device,proximal to or within a first region of the tubular conduit radiallyinterior of a first section of the wellbore tubular at 810. Method 800may further include detecting that the downhole device is within thefirst region of the tubular conduit at 815 and include actuating a firsttriggering device at 820. Method 800 may further include transitioningat least a first SSP at 825, stimulating a first region of thesubterranean formation at 830, and actuating a metering device todisplace a first internal volume of a sealing component holder todischarge a first portion of the plurality of sealing components, suchas at least one ball sealer, at 835 to seal SSPs in the open statewithin the first section of the wellbore tubular. Method 800 may or maynot include repositioning the downhole device during the stimulation ofthe particular region (e.g., the first region or the second region) ofthe subterranean formation and/or repositioning the downhole device foractuating the metering device to displace an internal volume (e.g., thefirst internal volume or the second internal volume) of the sealingcomponent holder. As an example, the downhole device may be positionedproximal to but outside of the first region of the tubular conduit forthe displacement of the first internal volume of the sealing componentholder. As an example, the proximal positioning to the first region ofthe tubular conduit may include positioning the downhole device withinan adjacent region of the tubular conduit, uphole or downhole from thefirst region of the tubular conduit. It is understood the positiondownhole may be achieved due to the axial location of the sealingcomponent holder within the downhole device relative to the section tobe sealed or the movement of the downhole device downhole occurs with atleast one section of the subterranean formation receiving wellborefluid.

Method 800 includes positioning the downhole device proximal to orwithin a second region of the tubular conduit radially interior of asecond section of the wellbore at 840, the second region spaced apartfrom the first region along the length of the wellbore tubular. Method800 may include repressurizing the tubular conduit at 845 and/ordetecting that the downhole device is in the second region of thetubular conduit at 850. Method 800 may include actuating a secondtriggering device at 855. Method 800 may include transitioning at leasta second SSP at 860, stimulating a second region of the subterraneanformation at 865, and actuating the metering device to displace a secondinternal volume of a sealing component holder to discharge a secondportion of the plurality of sealing components, such as at least oneball sealer, at 870 to seal SSPs in the open state within the secondsection of the wellbore tubular. Method 800 may or may not includerepositioning the downhole device during the stimulation of the secondregion of the subterranean formation and/or repositioning the downholedevice for the actuation of the metering device and displacement of thesecond internal volume of the sealing component holder. It is understoodthat the downhole device may be positioned proximal to but outside ofthe second region of the tubular conduit for the displacement of thesecond internal volume of sealing component holder. As an example, theproximal positioning to the second region of the tubular conduit mayinclude positioning the downhole device within an adjacent region of thetubular conduit, uphole or downhole from the second region of thetubular conduit. These processes may be repeated for additional regionswithin the tubular conduit and additional sections of the wellbore toseal areas of interest.

Pressurizing the tubular conduit at 805 may include pressurizing thetubular conduit in any suitable manner. As an example, the pressurizingat 805 may include pressurizing with a stimulant fluid, such as byflowing the stimulant fluid into the tubular conduit and/or providingthe stimulant fluid to the tubular conduit. The pressurizing at 805 maybe prior to the positioning at 810, concurrently with the positioning at810, subsequent to the positioning at 810, prior to the detecting at815, concurrently with the detecting at 815, subsequent to the detectingat 815, and/or prior to the actuating at 820. The pressurizing at 805 isillustrated in FIG. 22, wherein a stimulant fluid 70 is provided totubular conduit 42 of wellbore tubular 40. As also illustrated in FIG.22, and during the pressurizing at 805, SSPs 100 associated withwellbore tubular 40 may be in closed state 121, thereby permittingpressurization of the tubular conduit.

Positioning the downhole device may include positioning the downholedevice within the tubular conduit. The positioning of the downholedevice may be accomplished in any suitable manner and/or in any suitabledirection such as in the uphole direction or in the downhole direction.As an example, the positioning may include flowing and/or conveying thedownhole device in a downhole direction, such as downhole direction 29of FIG. 22, within a flow of the wellbore fluid 22, such as stimulantfluid 70. Alternatively, the downhole device may be conveyed on jointedpipe tubing, continuous jointless tubing or other means, such as awireline, and/or using a tractor. The wellbore fluid 22 may also includefracturing fluid with insubstantial amounts of proppant fluid (cleanfracturing fluid). The clean fracturing fluid may follow aproppant-laden wellbore fluid to displace the proppant-laden fluid intothe subterranean formation. As another example, the positioning mayinclude positioning with an umbilical, such as a wireline, asillustrated in FIG. 22 at 192. As yet another example, the positioningmay include autonomously positioning the downhole device. As anotherexample, the positioning may include landing, resting, stopping, and/orreceiving the downhole device on and/or with any suitable latch, catch,receiver, and/or platform that may form a portion of the wellboretubular and/or of the SSP, and/or that may extend within the tubularconduit. FIG. 22 illustrates positioning the downhole device 190A withina first region 105 of the tubular conduit 42 radially interior of afirst section 40A of the wellbore tubular 40.

Detecting the location of the downhole device may include detecting inany suitable manner. As an example, the detecting may include detectingvia and/or utilizing a detector, as discussed in more detail herein. Thedetecting may include one or more of detecting a casing collar of thewellbore tubular, detecting a component associated with the wellboretubular that has the potential to disturb magnetic lines of flux,detecting a velocity of the shockwave generation device within thewellbore tubular, detecting a residence time of the shockwave generationdevice within the wellbore tubular, detecting a distance of flow of theshockwave generation device along the length of the wellbore tubular,detecting a depth of the shockwave generation device within the wellboretubular, detecting a magnetic material that forms a portion of thewellbore tubular and/or SSP, and/or detecting a radioactive materialthat forms a portion of the wellbore tubular and/or SSP.

Actuating at 820 may include actuating the first triggering device toinitiate explosion of a first explosive charge of a plurality ofexplosive charges of the downhole device. The actuating of the firsttriggering device may include actuating to generate a first shockwavewithin the first region of the tubular conduit. This is illustrated inFIG. 23, where a shockwave 194 is illustrated within first region 105 oftubular conduit 42.

The actuating at 820 may include actuating responsive to any suitablecriteria. As an example, the actuating at 820 may be initiatedresponsive to the detecting the position of the downhole device (i.e.,responsive to detecting that the downhole device is within the firstregion of the tubular conduit). As another example, the actuating at 820may include actuating subsequent to the positioning in a region of thetubular conduit and/or responsive to completion of the positioningwithin the tubular conduit. The actuating at 820 may includeelectrically actuating, mechanically actuating, chemically actuating,wirelessly actuating, and/or actuating responsive to receipt of apressure pulse.

Transitioning the first SSP at 825 may include transitioning one or morefirst SSPs from respective closed states to respective open statesresponsive to receipt of the first shockwave with greater than thethreshold shockwave intensity by the one or more first SSPs. This isillustrated in FIG. 23, with SSPs 100 that are present within firstregion 105 of tubular conduit 42 being transitioned to open state 122responsive to receipt of shockwave 194. As also illustrated in FIG. 23,the transitioning at 825 may further include transitioning the SSPs 100to open state 122 while maintaining one or more SSPs 100 that are upholefrom the first SSP in respective closed states 121. The first SSPs andthe second SSPs also may be referred to herein as being spaced-apart, orlongitudinally spaced-apart, along a length of the wellbore tubular, andthis selective transitioning of the SSPs within the first region 105 ofthe tubular conduit 42 and not the other SSPs may be due to the limited,or maximum, effective distance, or propagation distance, of theshockwave within a wellbore fluid 22 that extends within tubular conduit42, as is discussed herein. Examples of the maximum effective distanceof the shockwave are disclosed herein, and the one or more closed SSPsmay be spaced-apart from the downhole device by greater than the maximumeffective distance of the shockwave.

Stimulating the first region of the subterranean formation at 830 mayinclude stimulating any suitable first region of the subterraneanformation that may be proximal to and/or associated with the firstregion of the tubular conduit. The stimulating at 830 may includestimulating responsive to, or directly responsive to, the actuating at820 and/or the transitioning at 825. As an example, and as illustratedin FIG. 23, transitioning the one or more first SSPs 100 to open state122 may permit stimulant fluid 70 to flow from tubular conduit 42 andinto subterranean formation 34, thereby permitting stimulation of thesubterranean formation.

Actuating the metering device at 835 includes actuating the meteringdevice to displace a first internal volume of a sealing component holderto discharge a first portion of the plurality of sealing components,such as at least one ball sealer, to seal SSPs in the open state withinthe first region of the tubular conduit. Actuating at 835 may includereleasing the first portion of the plurality of sealing components fromthe downhole device and flowing the first portion of the plurality ofsealing components, via the tubular conduit, to and/or into engagementwith the one or more first SSPs. As illustrated in FIG. 24, sealingcomponents 182 have been released into tubular conduit 42. Asillustrated in FIG. 25, engagement between the first portion of theplurality of sealing components 182 and the one or more first SSPs 100in the first region 105 of the tubular conduit 42 within the firstsection 40A of the wellbore tubular 40 may restrict fluid flow 70 fromthe tubular conduit 42 via the one or more first SSPs 100.

It is within the scope of the present disclosure that the actuating at835 may include actuating the metering device in any suitable manner. Asexamples, the actuating at 835 may include electrically actuating,mechanically actuating, and/or wirelessly actuating.

This is illustrated in FIGS. 24-25. In FIG. 24, sealing components 182in the form of ball sealers are depicted as flowing within a flow ofstimulant fluid 70 in downhole direction 29 within tubular conduit 42.In FIG. 25, the ball sealers 182 have engaged with the one or more firstSSPs 100 that are present within first region 105 of the tubular conduitand restrict fluid flow there through. The actuating at 835 may beperformed with any suitable timing and/or sequence within method 800 todeliver the first portion of the plurality of sealing components to theone or more first SSPs 100 in the open state within first region 105 oftubular conduit 42.

Positioning the downhole device at 840 may include moving the downholedevice to a second region of the tubular conduit that is spaced-apartfrom the first region of the tubular conduit. The positioning at 840 maybe accomplished in any suitable manner and may be performed similarly,or at least substantially similarly, to the positioning at 810. Asillustrated in the transition from FIG. 23 to FIG. 24, the positioningat 840 may include moving downhole device 190A in an uphole direction 28such that the downhole device is within a second region 107 of tubularconduit 42 radially interior of second section 40B of wellbore tubular40.

Repressurizing the tubular conduit at 845 may include repressurizingwith the stimulant fluid 70. The repressurizing at 845 may be performedat least substantially similar to the pressurizing at 805. When thepressurizing at 805 includes flowing and/or providing the stimulantfluid to the tubular conduit, the flowing and/or providing may beperformed continuously, or at least substantially continuously, during aremainder of method 800. Under these conditions, the repressurizing at845 may be responsive to, or a result of, operative sealing engagementbetween the first portion of the plurality of sealing components and theone or more first SSPs, as accomplished during the actuating at 835.

The repressurizing at 845 may be performed with any suitable timingand/or sequence within method 800. As examples, the repressurizing at845 may be performed subsequent to the actuating at 835 and prior to theactuating at 855.

Detecting that the downhole device is in the second region of thetubular conduit at 850 may include detecting in any suitable manner. Asan example, the detecting at 850 may be similar, or at leastsubstantially similar, to the detecting at 815.

Actuating the second triggering device at 855 may include actuating toinitiate explosion of a second explosive charge and/or to generate asecond shockwave within the second region of the tubular conduit. Theactuating at 855 may be performed in any suitable manner and may besimilar, or at least substantially similar, to the actuating at 820 andmay be responsive, or at least partially responsive, to the detecting at850. The actuating at 855 is illustrated in FIG. 26. Therein, downholedevice 190A is present within second region 107 of tubular conduit 42and has initiated explosion of a second explosive charge to generate asecond shockwave 194 within wellbore fluid 22 that extends within thetubular conduit 42.

Transitioning the second SSP at 860 may include transitioning one ormore second SSPs from respective closed states to respective open statesresponsive to receipt of the second shockwave with greater than thethreshold shockwave intensity by the one or more second SSPs. Ingeneral, the transitioning at 860 may be similar, or at leastsubstantially similar, to the transitioning at 825, which is discussedherein. The transitioning at 860 is illustrated in FIG. 26. Therein, oneor more second SSPs 100 that are present within second portion 107 oftubular conduit 42 are transitioned to respective open states 122responsive to receipt of shockwave 194.

Stimulating the second region of the subterranean formation at 865 mayinclude stimulating any suitable second region of the subterraneanformation that is proximal to and/or associated with the second regionof the tubular conduit. The stimulating at 865 may be at leastsubstantially similar to the stimulating at 830 and may be responsiveto, or directly responsive to, the actuating at 855 and/or thetransitioning at 860. The stimulating at 865 includes flowing stimulantfluid 70 from tubular conduit 42 into subterranean formation 34 via theone or more second SSPs 100 that are present within second region 107 ofthe tubular conduit 42.

The stimulating at 865 may be performed with any suitable timing and/orsequence within method 800. As examples, the stimulating at 865 may beperformed subsequent to the actuating at 835, subsequent to thepositioning at 840 and may or may not include repositioning the downholedevice uphole or downhole from the second region prior to stimulating at865, subsequent to the repressurizing at 845, subsequent to thedetecting at 850, and/or prior to the actuating at 870.

Actuating the metering device at 870 may be similar, or at leastsubstantially similar, to the actuating at 835, which is discussedherein. The actuating at 870 includes releasing the second portion ofthe plurality of sealing components from the downhole device and flowingthe second portion of the plurality of sealing components, via thetubular conduit, to and/or into engagement with the one or more secondSSPs. Engagement between the second portion of the plurality of sealingcomponents and the one or more second SSPs may restrict fluid flow fromthe tubular conduit via the one or more second SSPs. This is illustratedin FIGS. 27-28. In FIG. 27, sealing components 182 in the form of ballsealers are depicted as flowing within a flow of stimulant fluid 70 indownhole direction 29 within tubular conduit 42 from the downhole device190A positioned within a third region 111 of the tubular conduit 42within a third section (shown as 40C in FIG. 28) of the wellbore tubular40. In FIG. 28, the ball sealers 182 have engaged with the one or morefirst SSPs 100 that are present within second region 107 of the tubularconduit and restrict fluid flow there through. The actuating at 870 maybe performed with any suitable timing and/or sequence within method 800to deliver the second portion of the plurality of sealing components tothe one or more first SSPs 100 in the open state within second region107 of tubular conduit 42 within second section 40B of the wellboretubular 40.

The actuating at 870 may be performed with any suitable timing and/orsequence within method 800. As an example, the actuating at 870 may beperformed subsequent to the positioning at 840 and may or may notinclude repositioning the downhole device proximal to or within thesecond region prior to actuating at 870, subsequent to therepressurizing at 845, subsequent to the detecting at 850, subsequent tothe actuating at 855, subsequent to the transitioning at 860, and/orsubsequent to the stimulating at 865.

It is understood that the methods for providing sealing componentswithin a hydrocarbon well may be used in connection with fracturingapplications and/or re-fracturing applications using a perforation gun.FIG. 29 is a flowchart depicting method 900, according to the presentdisclosure, of providing sealing components within a hydrocarbon well tobe re-fractured. It is understood that the process with respect tore-fracturing the wellbore tubular may additionally or alternatively beused in the original fracturing of the wellbore tubular. Method 900 mayinclude identifying an area of interest within the hydrocarbon well tobe re-fractured at 910. The hydrocarbon well to be re-fractured may be awell previously perforated at spaced-apart intervals along the length ofthe wellbore tubular within the area of interest for re-fracturing. Itis understood that the refracturing method may also be used with respectto a wellbore with SSPs in both the opened and closed state atspaced-apart intervals along the length of the wellbore tubular withinthe area of interest for re-fracturing. The opened SSPs to be sealedwith sealing components and the closed SSPs to be opened forre-fracturing operations.

Method 900 includes positioning the downhole device proximal to orwithin a first region within the tubular conduit radially interior of afirst section of the wellbore tubular at 920. Method 900 includesactuating the metering device at 930 to displace a first internal volumeof the sealing component holder to discharge a first portion of theplurality of sealing components through the opening of the sealingcomponent holder into the tubular conduit to sealing engage with theprevious perforations within the first section of the wellbore tubular.Method 900 includes positioning the downhole device proximal to orwithin a second region within the tubular conduit radially interior of asecond section of the wellbore tubular at 940. Method 900 includesactuating the metering device at 950 to displace a second internalvolume of the sealing component holder to discharge a second portion ofthe plurality of sealing components through the opening of the sealingcomponent holder into the tubular conduit to sealing engage with theprevious perforations within the second section of the wellbore tubular.

Method 900 may further include pressurizing the tubular conduit with awellbore fluid at 915 and at 935; detecting that the downhole device isproximal to or within a first region of the tubular conduit at 925 or asecond region of the tubular conduit at 945; repeating the process ofsealing the previous perforations (e.g., 910-950) within additionalsections of the wellbore tubular until the previous perforations withinthe area of interest for re-fracturing have been sealed with the sealingcomponents at 955.

Once the previous perforations within the area of interest forre-fracturing have been sealed with the sealing components, method 900may include positioning a perforation gun within a region of the tubularconduit radially interior of an unperforated section of the wellboretubular within the area of interest for re-fracturing at 960;positioning the downhole device within the tubular conduit or removingthe downhole device from the tubular conduit such that detonation of theperforation gun does not significantly damage the downhole device at965; detonating the perforation gun to form new perforations within thewellbore tubular at 970; positioning the downhole device proximal to orwithin the region of the tubular conduit radially interior of the newlyperforated section of the wellbore tubular (a first newly perforatedsection) at 975; displacing an additional internal volume of the sealingcomponent holder of the downhole device to discharge an additionalportion of the plurality of sealing components from within an additionalregion of the sealing component holder through the opening of thesealing component holder to seal the new perforations within the newlyperforated section of the wellbore tubular (first newly perforatedsection) at 980; and repeating the perforation process for re-fracturing(e.g., 960-980) until the re-fracturing of the wellbore tubular withinthe area of interest has been completed at 985. FIG. 30 illustrates aconfiguration for re-fracturing using the perforation gun 162 (depictedafter detonation showing damage) to provide new perforations 163 withinregion 161 of the tubular conduit 42 radially interior of the newlyperforated section 40D of the wellbore tubular 40 with the downholedevice 190 positioned uphole of the perforation gun 162. Sealingcomponents 182 are shown within the previously formed perforations.Although not depicted, alternatively the downhole device 190 may beintegral with the perforation gun 162 forming a single device having thedownhole device 190 section positioned on top of the perforation gun 162section. The opening to the sealing component holder may be located inthe side or top of the device. This embodiment allows a single unit tobe utilized with perforation operations.

As an example, sealing the previous perforations during re-fracturing ahydrocarbon well may include using a sealing component holder includingat least a first plurality of degradable sealing components within afirst region of the sealing component holder occupying the firstinternal volume and a second plurality of degradable sealing componentswithin a second region of the sealing component holder occupying thesecond internal volume. The sealing component holder may have additionalregions occupying additional internal volumes of the sealing componentholder and including additional pluralities of degradable sealingcomponents. The first plurality of sealing components, the secondplurality of sealing components, and any additional pluralities ofsealing components may have different degradation rates. As an example,the first region proximal the opening of the sealing component holdercontains a first plurality of degradable sealing components with thegreatest rate of degradation and the region within the sealing componentholder furtherest from the opening contains a plurality of degradablesealing components with the lesser rate of degradation. As an example,the first plurality of degradable sealing components may have adifferent rate of degradation than the second plurality of degradablesealing components.

It is understood that the methods for providing sealing componentswithin a well may be used within an injection well used in connectionwith hydrocarbon production. An injection well may be used to assist insustaining formation pressure within the reservoir and provide fluid tosweep the subterranean formation and push hydrocarbons within thereservoir (reservoir fluid) towards a neighboring hydrocarbon productionwell. FIG. 31 is a flowchart depicting method 1100, according to thepresent disclosure, of providing sealing components within an injectionwell to temporarily seal portions of the subterranean formation todivert the wellbore fluid within the injection well to other areaswithin the well and surrounding subterranean formation. Method 1100 mayinclude identifying sections of an injection well for which a wellborefluid, such as an injection fluid may be diverted to one or more othersections of such well at 1110. The injection fluid may be predominantlywater, predominantly carbon dioxide, as well as other suitable fluids.As an example, the identified injection well may include at least twosections of the wellbore tubular that are ineffectively providinginjection fluid into the subterranean formation to provide pressure.Each of the at least two sections are spaced apart from each other alongthe length of the wellbore tubular. Such sections may be identifiedusing core samples, tracers, and/or production logs to determine wherethe injection fluid is exiting the wellbore such that the injectionfluid is well swept and ineffective in providing pressure to thereservoir. Associated with each section of the wellbore tubular is aradially interior region within the conduit, such as a first regionwithin the tubular conduit associated with the first section of thewellbore tubular and a second region within the tubular conduitassociated with the second section of the wellbore tubular. Theinjection well also includes at least a third region within the tubularconduit associated with the third section of the wellbore tubular. Eachsection of the wellbore tubular is also associated with a radiallyexterior region of the subterranean formation.

Method 1100 includes positioning the downhole device proximal to orwithin a region (e.g., the first region or the second region) of thetubular conduit at 1105 and providing a first portion of the pluralityof sealing components, such as chemical diverters or ball sealers, intothe tubular conduit of the wellbore tubular, and sealing thesubterranean formation proximate the section with chemical diverters oropenings within the wellbore tubular with ball sealers at 1120. Thesealing includes actuating a metering device to displace a firstinternal volume of the sealing component holder to discharge a firstportion of the plurality of sealing components, such as chemicaldiverters or ball sealers, through the opening within the sealingcomponent holder into the tubular conduit. Method 1100 includespositioning the downhole device proximal to or within another region ofthe tubular conduit at 1125 and sealing another of the sections (e.g.,other of the first region or the second region not yet sealed) of thewellbore tubular with a second portion or the plurality of sealingcomponents as 1130. Additional ineffective sections of the injectionwell may be identified and provided additional portions of the pluralityof sealing components to divert the injection fluid into other sectionsnot taking in sufficient injection fluid to strategically increase thepressure within the reservoir and maintain production.

FIG. 32 illustrates an injection well 11. The wellbore tubular 40includes a first section 40A of the wellbore tubular 40, a secondsection 40B of the wellbore tubular 40, and a third section 40C of thewellbore tubular 40. A first region 105 within the tubular conduit 42 isradially interior of the first section 40A of the wellbore tubular 40, asecond region 107 within the tubular conduit 42 is radially interior ofthe second section 40B of the wellbore tubular 40, and a third region111 within the tubular conduit 42 is radially interior of the thirdsection 40C of the wellbore tubular 40. The first section 40A, thesecond section 40B, and the third section 40C of the wellbore tubular 40contain perforations 163. Downhole device 190 is positioned within thetubular conduit 42 proximate the second region 107 of the tubularconduit 42 proximal the first section 40A of the wellbore tubular 40 andused to seal off the subterranean formation 34 proximate the firstsection 40A of the wellbore tubular 40 from the tubular conduit 42 andthe injection fluid.

In the present disclosure, several of the illustrative, non-exclusiveexamples have been discussed and/or presented in the context of flowdiagrams, or flow charts, in which the methods are shown and describedas a series of blocks, or steps. Unless specifically set forth in theaccompanying description, it is within the scope of the presentdisclosure that the order of the blocks may vary from the illustratedorder in the flow diagram, including with two or more of the blocks (orsteps) occurring in a different order and/or concurrently. It is alsowithin the scope of the present disclosure that the blocks, or steps,may be implemented as logic, which also may be described as implementingthe blocks, or steps, as logics. In some applications, the blocks, orsteps, may represent expressions and/or actions to be performed byfunctionally equivalent circuits or other logic devices. The illustratedblocks may, but are not required to, represent executable instructionsthat cause a computer, processor, and/or other logic device to respond,to perform an action, to change states, to generate an output ordisplay, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and asecond entity means one of (1) the first entity, (2) the second entity,and (3) the first entity and the second entity. Multiple entities listedwith “and/or” should be construed in the same manner, i.e., “one ormore” of the entities so conjoined. Other entities may optionally bepresent other than the entities specifically identified by the “and/or”clause, whether related or unrelated to those entities specificallyidentified. Thus, as a non-limiting example, a reference to “A and/orB,” when used in conjunction with open-ended language such as“comprising” may refer, in one embodiment, to A only (optionallyincluding entities other than B); in another embodiment, to B only(optionally including entities other than A); in yet another embodiment,to both A and B (optionally including other entities). These entitiesmay refer to elements, actions, structures, steps, operations, values,and the like.

As used herein, the phrase “at least one,” in reference to a list of oneor more entities should be understood to mean at least one entityselected from any one or more of the entity in the list of entities, butnot necessarily including at least one of each and every entityspecifically listed within the list of entities and not excluding anycombinations of entities in the list of entities. This definition alsoallows that entities may optionally be present other than the entitiesspecifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entitiesspecifically identified. Thus, as a non-limiting example, “at least oneof A and B” (or, equivalently, “at least one of A or B,” or,equivalently “at least one of A and/or B”) may refer, in one embodiment,to at least one, optionally including more than one, A, with no Bpresent (and optionally including entities other than B); in anotherembodiment, to at least one, optionally including more than one, B, withno A present (and optionally including entities other than A); in yetanother embodiment, to at least one, optionally including more than one,A, and at least one, optionally including more than one, B (andoptionally including other entities). In other words, the phrases “atleast one,” “one or more,” and “and/or” are open-ended expressions thatare both conjunctive and disjunctive in operation. For example, each ofthe expressions “at least one of A, B and C,” “at least one of A, B, orC,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B,and/or C” may mean A alone, B alone, C alone, A and B together, A and Ctogether, B and C together, A, B and C together, and optionally any ofthe above in combination with at least one other entity.

In the event that any patents, patent applications, or other referencesare incorporated by reference herein and (1) define a term in a mannerthat is inconsistent with and/or (2) are otherwise inconsistent with,either the non-incorporated portion of the present disclosure or any ofthe other incorporated references, the non-incorporated portion of thepresent disclosure shall control, and the term or incorporateddisclosure therein shall only control with respect to the reference inwhich the term is defined and/or the incorporated disclosure was presentoriginally.

As used herein the terms “adapted” and “configured” mean that theelement, component, or other subject matter is designed and/or intendedto perform a given function. Thus, the use of the terms “adapted” and“configured” should not be construed to mean that a given element,component, or other subject matter is simply “capable of” performing agiven function but that the element, component, and/or other subjectmatter is specifically selected, created, implemented, utilized,programmed, and/or designed for the purpose of performing the function.It is also within the scope of the present disclosure that elements,components, and/or other recited subject matter that is recited as beingadapted to perform a particular function may additionally oralternatively be described as being configured to perform that function,and vice versa.

As used herein, the phrase, “for example,” the phrase, “as an example,”and/or simply the term “example,” when used with reference to one ormore components, features, details, structures, embodiments, and/ormethods according to the present disclosure, are intended to convey thatthe described component, feature, detail, structure, embodiment, and/ormethod is an illustrative, non-exclusive example of components,features, details, structures, embodiments, and/or methods according tothe present disclosure. Thus, the described component, feature, detail,structure, embodiment, and/or method is not intended to be limiting,required, or exclusive/exhaustive; and other components, features,details, structures, embodiments, and/or methods, including structurallyand/or functionally similar and/or equivalent components, features,details, structures, embodiments, and/or methods, are also within thescope of the present disclosure.

INDUSTRIAL APPLICABILITY

The downhole devices, wells, and methods disclosed herein are applicableto the oil and gas industry.

It is believed that the disclosure set forth above encompasses multipledistinct inventions with independent utility. While each of theseinventions has been disclosed in its preferred form, the specificembodiments thereof as disclosed and illustrated herein are not to beconsidered in a limiting sense as numerous variations are possible. Thesubject matter of the inventions includes all novel and non-obviouscombinations and subcombinations of the various elements, features,functions and/or properties disclosed herein. Similarly, where theclaims recite “a” or “a first” element or the equivalent thereof, suchclaims should be understood to include incorporation of one or more suchelements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certaincombinations and subcombinations that are directed to one of thedisclosed inventions and are novel and non-obvious. Inventions embodiedin other combinations and subcombinations of features, functions,elements and/or properties may be claimed through amendment of thepresent claims or presentation of new claims in this or a relatedapplication. Such amended or new claims, whether they are directed to adifferent invention or directed to the same invention, whetherdifferent, broader, narrower, or equal in scope to the original claims,are also regarded as included within the subject matter of theinventions of the present disclosure.

What is claimed is:
 1. A downhole device for providing sealingcomponents within a well comprising: a core; a sealing component holderpositioned within the core including an opening to an external surfaceof the core; a plurality of sealing components positioned within thesealing component holder; a metering device constructed and arranged todisplace an internal volume of the sealing component holder anddischarge through the opening a portion of the plurality of sealingcomponents contained within the sealing component holder; and a coverpositioned over the opening, the cover constructed and arranged to allowthe portion of the sealing components to exit the opening upondisplacement of the internal volume of the sealing component holder. 2.The device of claim 1, wherein the sealing component holder ispositioned at least proximal the distal end of the core.
 3. The deviceof claim 1, wherein the plurality of sealing components are ball sealersor chemical diverters.
 4. The device of claim 1, wherein the pluralityof sealing components are ball sealers.
 5. The device of claim 4,wherein the sealing component holder includes a plurality ofspaced-apart regions, each region including a plurality of ball sealers,the plurality of ball sealers within one region having a substantiallydifferent rate of degradation than the plurality of ball sealers in eachadjacent region.
 6. The device of claim 4, wherein the well includes awellbore tubular forming a tubular conduit having in inner diameter inthe range of from 90 mm to 178 mm, and wherein the sealing componentholder and metering device are placed proximal the distal end of thecore and a portion of the plurality of the ball sealers have a maximumouter dimension greater than 32 mm.
 7. The device of claim 6, wherein aportion of the plurality of the ball sealers have a maximum outerdimension of less than 15 mm.
 8. The device of claim 4, wherein aportion of the plurality of the ball sealers have a maximum outerdimension of less than 15 mm.
 9. The device of claim 1, wherein theplurality of sealing components are chemical diverters which areselected from benzoic acid flakes, polyglycolic acid polymer beads, andpolylactic acid polymer beads.
 10. The device of claim 1, wherein themetering device includes a pump or a motor operatively connected to amember positioned within the sealing component holder such that, uponactuation of the pump or motor, the member displaces an internal volumeof the sealing component holder.
 11. The device of claim 1, wherein themetering device includes a pump operatively connected to the sealingcomponent holder such that, upon actuation of the pump, a displacementfluid is introduced into an inlet of the sealing component holderdisplacing an internal volume of the sealing component holder.
 12. Thedevice of claim 11, wherein the metering device includes a pump and thepump is a solid state, piezoelectric pump.
 13. A method for providingsealing components within a well including a wellbore and a wellboretubular extending within the wellbore, the wellbore tubular defining atubular conduit, the method comprising: positioning a downhole deviceproximal to or within a first region within the tubular conduit radiallyinterior of a first section of the wellbore tubular, the downhole devicecomprising: a core, a sealing component holder positioned within thecore including an opening to an external surface of the core, aplurality of sealing components positioned within the sealing componentholder, a metering device constructed and arranged to displace aninternal volume of the sealing component holder and discharge sealingcomponents through the opening, and a cover positioned over the opening,the cover constructed and arranged to allow the sealing components toexit the opening upon displacement of the internal volume of the sealingcomponent holder; actuating the metering device to displace a firstinternal volume of the sealing component holder to discharge a firstportion of the plurality of sealing components through the opening intothe tubular conduit; positioning the downhole device proximal to orwithin a second region within the tubular conduit radially interior of asecond section of the wellbore tubular, the second region spaced apartfrom the first region along the length of the wellbore tubular; andactuating the metering device to displace a second internal volume ofthe sealing component holder to discharge a second portion of theplurality of sealing components through the opening into the tubularconduit.
 14. The method of claim 13, wherein the downhole deviceincludes a plurality of explosive charges arranged on an externalsurface of the core and a plurality of triggering devices, each of theplurality of triggering devices is constructed and arranged toselectively initiate explosion of a selected portion of the plurality ofexplosive charges; and wherein the wellbore tubular includes a pluralityof selective stimulation ports disposed along a length of the wellboretubular; and wherein the method further comprises: actuating a firsttriggering device of the plurality of triggering devices to initiateexplosion of a first portion of the plurality of explosive charges togenerate a first shockwave within the first region of the tubularconduit to transition a first portion of the selective stimulation portsto an open state; and actuating a second triggering device of theplurality of triggering devices to initiate explosion of a secondportion of the plurality of explosive charges to generate a secondshockwave within the second region of the tubular conduit to transitiona second portion of the selective stimulation ports to an open state,wherein the first portion of the plurality of sealing components sealthe first portion of the selective stimulation ports and the secondportion of the plurality of sealing components seal the second portionof the selective stimulation ports.
 15. The method of claim 13, whereinthe sealing component holder forms a majority of an internal volume ofthe core, the wellbore tubular has been previously perforated atspaced-apart intervals along its length, and at least a portion of theplurality of the sealing components are used to seal the previouslyperforated spaced-apart intervals within a re-fracturing area ofinterest along the length of the wellbore tubular.
 16. The method ofclaim 15, wherein the plurality of sealing components includes at leasta first plurality of degradable sealing components within a first regionof the sealing component holder occupying the first internal volume anda second plurality of degradable sealing components within a secondregion of the sealing component holder occupying the second internalvolume, the first plurality of degradable sealing components having adifferent rate of degradation than the second plurality of degradablesealing components, and wherein the first section of the wellboretubular is one of the previously perforated spaced-apart intervals alongthe length of the wellbore tubular and the second section of thewellbore tubular is another of the previous spaced-apart intervals alongthe length of the wellbore tubular.
 17. The method of claim 16, furthercomprising: positioning a perforation gun within a region of the tubularconduit radially interior of an unperforated section of the wellboretubular within the re-fracturing area of interest after the previouslyperforated spaced-apart intervals have been sealed with degradablesealing components, positioning the downhole device such that detonationof the perforation gun does not significantly damage the downholedevice; detonating the perforation gun to form new perforations withinthe unperforated section of the wellbore tubular, positioning thedownhole device proximal to or within the region of the tubular conduitradially interior of newly perforated section of the wellbore tubular,displacing an additional internal volume of the sealing component holderto discharge an additional portion of the plurality of sealingcomponents through the opening, wherein the additional internal volumeincludes a plurality of non-degradable sealing components within anadditional region of the sealing component holder.
 18. The method ofclaim 17, wherein the positioning, detonating, and displacing arecontinued until the re-fracturing of the wellbore tubular within thearea of interest is completed.
 19. The method of claim 13, wherein thewell is an injection well and includes at least three sections of thewellbore tubular that are passing injection fluid into the subterraneanformation to create pressure and displace hydrocarbons within thereservoir to assist a hydrocarbon well producing hydrocarbons, the atleast three sections include the first section, the second section, anda third section of the wellbore tubular, each of the at least threesections spaced apart from each other along the length of the wellboretubular, and wherein the subterranean formation proximate the firstsection and the second section is sealed such that the injection fluidis diverted to the subterranean formation proximate the third section ofthe wellbore tubular.
 20. The method of claim 19, the method furthercomprises: identifying locations of the first section and the secondsection using production logs to determine the sections of the injectionwell that are ineffective in creating pressure within the reservoir. 21.A well comprising: a wellbore; a wellbore tubular extending within thewellbore, the wellbore tubular defining a tubular conduit; and adownhole device disposed within the tubular conduit, the downhole devicecomprising: a core; a sealing component holder positioned within thecore including an opening to an external surface of the core; aplurality of sealing components positioned within the sealing componentholder; a metering device constructed and arranged to displace aninternal volume of the sealing component holder and discharge throughthe opening a portion of the plurality of sealing components containedwithin the sealing component holder; and a cover positioned over theopening, the cover constructed and arranged to allow the portion of thesealing components to exit the opening upon displacement of the internalvolume of the sealing component holder.